Opt-in units.  EPA is not finalizing the opt-in provisions that were discussed in the Transport Rule proposal.  EPA proposed opt-in provisions to allow non-covered units to voluntarily opt in to any of the proposed Transport Rule trading programs and receive allocations reflecting 70 percent of the unit's emissions before opting in.  These allowances were above the state-specific budgets developed under the Transport Rule to eliminate a state's significant contribution to nonattainment and interference with maintenance.  In theory, an opt-in unit that makes reductions below its baseline and sells the freed-up allowances is effectively substituting its new, lower-cost reductions for higher-cost reductions otherwise required by a covered EGU, with the result that the state's significant contribution is still eliminated but at a lower total program cost.
      EPA notes that theoretical benefits anticipated from allowing opt-ins did not materialize in prior trading programs with opt-in provisions.  The Acid Rain Program has about 23 opt in units; the NOX Budget Trading Program had five opt-in units; andno units opted into the CAIR programs.  As a group, these opt-in units neither eased the achievement of required emission reductions in past trading programs, nor reduced overall program costs.
      In the proposal,  EPA requested comment on the opt-in provisions, specifically regarding:  what are the benefits of and concerns about including opt-in provisions; how to ensure units are not credited for emission reductions the units would have made anyway; whether the proposed 30 percent reduction (i.e., application of the 70 percent multiplier to baseline emissions) or some other percentage reduction, or no reduction, should be applied to the baseline emission rate used in determining allocations; and whether any additional percentage reduction (such as 45 percent) should be applied to SO2 Group 1 opt-in units in Phase II to reflect the stricter limits for covered units.
      Some commenters argued that increasing the Transport Rule budgets for opt-ins would undermine the goal of CAA section 110(a)(2)(D)(i)(I) to eliminate a state's significant contribution to nonattainment and interference with maintenance.  One commenter stated that it does not favor allowing sources that are not subject to the emission reduction requirements to be issued allowances that would increase the overall state emission budgets, due to the uncertainty that any reductions made by such units would be surplus, verifiable, permanent and enforceable.  This could compromise the integrity of the EGU emission reduction requirements of the Transport Rule and jeopardize assurance that a state's significant contribution would be eliminated, as required by the Court in North Carolina.  Other commenters claim that, while no cheap tons are available from non-EGUs and EPA is right not to require non-EGU reductions, EPA should nonetheless allow non-EGUs to choose voluntarily to be covered by opting in.
      As mentioned previously, the final Transport Rule does not include any opt-in provisions either in the FIPs or in the provisions allowing modification or replacement of the FIPs through submission of trading program provisions in SIPs.  EPA has several reasons for not adopting provisions to allow opt-in units.  First, as mentioned above, historically, very few units have opted in.  As of 2010, 28 units out of more than 4,700 covered units (23 units out of a total of about 3,600 covered units in the Acid Rain Program and 5 units out of a total of about 2,600 covered units in the NOX SIP Call) have opted in to EPA trading programs over the past 15 years.  In the Acid Rain Program, 3 of the units opted in and then, effective for 2005, opted out.  Four of the units opted in, immediately shut down, and continue to receive allowance allocations.  Four of the units opted in and continue to operate and receive allowance allocations.  Finally, 12 of the units opted in, after CAIR was finalized, in order to receive allowances usable for compliance in the CAIR SO2 trading program.  Because CAIR will be replaced by this Transport Rule, EPA anticipates that these 12 units will opt out of the Acid Rain Program.  In the NOX Budget Trading Program, 3 plants with 5 opt-in units received allocations between 2003 and 2008.
      Moreover, EPA has determined that the inclusion of opt-in units in the Transport Rule trading programs would undermine the rule's objective of addressing emissions in each state that significantly contribute to nonattainment or interfere with maintenance in other states.  As explained above, EPA has established budgets plus variability limits that states must meet to ensure that the significant contribution to nonattainment and interference with maintenance identified by EPA is addressed.  If EPA were to allow opt-ins, and if any opt-in unit were to receive an allocation of allowances for emissions that would be reduced even if the units did not opt in, then the inclusion of that opt-in unit in the program would allow the sources covered by the Transport Rule to emit in excess of the budget plus variability limit with no new, offsetting reduction in emissions.  For example, after a unit would opt in, process or fuel changes made for economic reasons (rather than due to any regulatory requirements), or installation of new emission controls or fuel-switching conducted to meet future, non-Transport Rule regulatory requirements, could result in emission reductions that would have occurred "anyway" (i.e., even if the unit had not opted in), and the opt-in unit would be allocated allowances for the portion of its baseline emissions that would be removed by these "anyway" reductions.  Allocations above the cap to opt-in units making "anyway" emission reductions would convert these reductions into extra allowances (i.e., authorizations to emit) usable by covered EGUs to meet their requirements to hold allowances for emissions.  Because the extra EGU emissions authorized by these extra allowances would not be offset by any new emission reductions by the opt-in units, this could threaten a state's ability to eliminate the significant contribution to nonattainment and interference with maintenance identified by EPA in the final rule.  Also, opt-in units, which are allocated allowances outside the state budget for covered units, could increase the possibility that a state's total emissions would exceed the state budget plus variability and thus that the assurance provisions would be triggered.
      This problem of allocating allowances for emissions that would have been reduced anyway is illustrated by the recent promulgation of the final rule, National Emission Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial, and Institutional Boilers and Process Heaters (76 FR 15608 (March 21, 2011))(" final Boiler MACT rule"), which requires certain industrial, commercial, and institutional boilers to meet maximum achievable control technology (MACT) standards for emissions of specified hazardous air pollutants, such as hydrogen chloride (HCL) and mercury (Hg).  Some of the control technologies that can be used to meet these standards will also provide significant reductions of SO2 emissions.  For example, a boiler may use a wet scrubber or the combination of a dry sorbent injection system and a fabric filter (among other options) to meet the applicable HCL standard or may use a wet scrubber or a combination of activated carbon injection and a fabric filter (among other options) to meet the applicable Hg standard.  See 76 FR 15614 (describing testing and compliance requirements when such controls are used to meet these standards); and Memo from Brian Shrager to Amanda Singleton and Graham Gibson, Revised Methodology for Estimating Cost and Emissions Impacts for Industrial, Commercial and Institutional Boilers and Process Heaters National Emissions Standards for Hazardous Air Pollutants  --  Major Source (February 11, 2011), Document ID EPA-HQ-OAR-2009-0491-4036 (section 3.1, describing control options for HCL and Hg control).  In fact, EPA estimated that the new standards would result in emission reductions of not only the hazardous air pollutants directly subject to the standards, but also in other air pollutants such as SO2.  Specifically, EPA projected that compliance with the final Boiler MACT rule standards will result in about 431,000 tons of annual SO2 reductions from existing boilers subject to the final Boiler MACT rule.  This will comprise on average about a 46 percent reduction in SO2 emissions for this group of boilers.  Coal- and oil-fired boilers -- which are the boilers likely to have the most uncontrolled SO2 emissions and so would be the most likely types of units to consider opting into the Transport Rule trading programs if opting-in were allowed -- are projected to reduce about 409,000 tons of annual SO2 as a result of complying with the final Boiler MACT rule, or about a 50 percent reduction in SO2 emissions.  See Memo from Brian Shrager to Amanda Singleton and Graham Gibson, Appendix B-1, (where column CE represents baseline SO2 emissions and column CH represents SO2 reductions resulting from the final Boiler MACT rule compliance).  The amount of offsetting SO2 increases projected to result from final Boiler MACT rule compliance, e.g., from additional fuel being combusted to generate electricity to operate emission controls, is minor.  See 76 FR 15651 (Table 4) and 15653 (showing projected total SO2 reductions for all boilers and process heaters of about 442,000 tons and net SO2 reductions of about 440,000 tons).
      Consequently, a boiler subject to the final Boiler MACT rule may install a wet acid gas scrubber or a bag house in order to meet the HCL or Hg standard applicable to boilers under the final Boiler MACT rule and thereby achieve SO2 emission reductions.  If that boiler were to opt in to one of the Transport Rule SO2 trading programs during the year before installing these controls to comply with the final Boiler MACT rule, then the boiler would be allocated allowances for the unit's current tons of SO2 emissions and would not need to use these allowances for compliance under the Transport Rule once the final Boiler MACT-related controls were installed.  The allowances allocated to the boiler would be additional allowances above the Transport Rule trading budget for the state where the boiler was located.  As a result, the boiler would have freed-up allowances above the state trading budget that represent reductions that the boiler would have made anyway (i.e., even if the boiler had not opted in) and that could be sold to EGUs covered by the Transport Rule.  In effect, the opting-in of the boiler would result in the conversion of the boiler's SO2 reductions from the final Boiler MACT rule into increased emissions above the state trading budget from EGUs subject to the Transport Rule.
      Commenters addressed this issue.  For instance, one commenter suggested that SO2 reductions made by a boiler under the final Boiler MACT rule should be eligible for opt-in provision allowances under the Transport Rule trading programs.  Another commenter stated that, given the uncertainty that reductions made by opt-in units would be surplus, verifiable, permanent, and enforceable, opt-in provisions could compromise the integrity of the EGU emission reductions.
      For the reasons explained above, EPA agrees with the latter commenter.  Further, EPA notes that none of the commenters supporting adoption of the opt-in provisions suggested any revision to the proposed opt-in provisions that would address this problem.  While the proposed opt-in provisions would limit an opt-in unit's allocation for a control period by calculating the allocation using the lesser of the unit's pre-opt-in SO2 emission rate or the most stringent SO2 emission rate applicable in that control period, this would not address SO2 rate reductions that are not directly required by the final Boiler MACT rule but that are a secondary result of using and operating certain emission controls installed to comply with the HCL or Hg standards under the final Boiler MACT rule.  Because the secondary SO2 reductions will vary depending on the type of controls installed and on the extent to which the controls are used, and a boiler may use a combination of emission controls and other approaches to reduce HCL or Hg emissions (such as fuel switching), EPA believes that it is highly unlikely that opt-in provisions could prevent allocation for "anyway" emission reductions resulting from compliance with the final Boiler MACT rule.  EPA therefore believes that the final Boiler MACT rule provides a concrete example of why adoption of opt-in provisions could undermine the rule's objective of addressing emissions in each state that significantly contribute to nonattainment or interfere with maintenance in other states.  EPA notes that the final Boiler MACT rule, of course, is simply one example of how allocations for "anyway" reductions could occur and undermine the statutory requirements of the Transport Rule.
C. Compliance Deadlines
1. Alignment with NAAQS Attainment Deadlines
a. Proposed Rule.
      EPA proposed an initial phase of reductions in 2012 followed by a second phase in 2014.  Specifically, EPA proposed that sources comply with annual SO2 and NOX requirements by January 1, 2012 and January 1, 2014 for the first and second phases, respectively.  Similarly, EPA proposed sources comply with ozone-season NOX requirements by May 1, 2012, and by May 1, 2014.  EPA chose these dates to coordinate with the NAAQS attainment deadlines and to assure that reductions are made as expeditiously as practicable.  The proposal also discussed how the compliance deadlines address the Court's concern about timing.
      Relationship to PM2.5 schedule.  For all areas designated as nonattainment with respect to the 1997 PM2.5 NAAQS, the SIP deadline for attaining that standard must be as expeditious as practicable but no later than April 2010, with a possible extension to no later than April 2015.  Many areas have already come into attainment by the April 2010 deadline due in part to reductions achieved under CAIR.  Because the 2010 deadline will have passed before the Transport Rule is finalized, EPA proposed to coordinate the deadline for eliminating significant contribution under this rule with respect to the 1997 PM2.5 NAAQS with the April 2015 deadline that applies to areas that will need an extension of the April 2010 deadline.  For all areas designated as nonattainment with respect to the 2006 24-hour PM2.5 NAAQS, the attainment deadline must be as expeditious as practicable but no later than December 2014 with a possible extension to as late as December 2019.
      Upwind emission reductions achieved by the 2014 emissions year will help areas that failed to meet the April 2010 deadline to meet the April 2015 deadline for the 1997 PM2.5 NAAQS.  These reductions will also help areas meet the December 2014 attainment deadline with respect to the 2006 PM2.5 NAAQS.  Any areas not meeting that deadline can request an extension of up to 5 years, to December 2019.
      Further, a deadline of January 1, 2014 also provides adequate and reasonable time for sources to plan for compliance with the Transport Rule and install any necessary controls.  EPA believes that this deadline is as expeditious as practicable for the installation of the controls needed for compliance (see further discussion in section VII.C.2).
      Relationship to Attainment Deadlines for Ozone.  Ozone nonattainment areas must attain permissible levels of ozone "as expeditiously as practicable," but no later than the date assigned by EPA in the ozone implementation rule (40 CFR part 51).  The areas designated nonattainment in 2004 with respect to the 1997 8-hour ozone NAAQS in the eastern United States were assigned maximum attainment dates corresponding to the end of the 2006, 2009, and 2012 ozone seasons.  Many areas have already attained due in part to CAIR, federal mobile source standards, and other local, state, and federal measures.  Those that have not yet attained the standard have maximum attainment dates ranging from 2010 (these are the 2009 areas that have been granted a 1-year extension due to clean data in 2009) to 2018.  Areas designated "serious" nonattainment areas have a June 2013 maximum attainment deadline.  The proposed Transport Rule's first phase of reductions in 2012 will help the remaining areas with June 2013 maximum attainment deadlines attain the 1997 8-hour ozone NAAQS by their deadline.  The reductions will also improve air quality in areas with later deadlines.
      Rationale for Requiring Reductions by 2012.  EPA proposed to require an initial phase of reductions by 2012.  EPA proposed that these reductions are necessary to ensure that significant contribution to nonattainment and interference with maintenance are eliminated as expeditiously as practicable.  This will in turn assist downwind states to achieve attainment as expeditiously as practicable as required by the CAA.  Because this final rule would replace CAIR, EPA could not assume that after this rule is finalized, EGUs would continue to emit at the reduced emissions levels achieved by CAIR.  Instead, it is the emission reductions requirements in the proposed FIPs that will determine the level of EGU emissions in the eastern United States.  For these reasons, EPA proposed to require an initial phase of reductions by 2012 which would ensure that existing and planned SO2 and NOX controls operate as anticipated.
      Addressing the Court's Concern About Timing.  As directed by the Court in North Carolina, 531 F.3d 896, and described previously, EPA  established the compliance deadlines in the proposed rule based on the respective NAAQS attainment requirements and deadlines applicable to the downwind nonattainment and maintenance sites.
 	The 2012 deadline for compliance with the limits on ozone-season NOX emissions is coordinated with the June 2013 maximum attainment deadline for serious ozone nonattainment areas (taking into account the need for reductions by 2012 to demonstrate attainment by that date).  This deadline is also consistent with the requirement that states attain the NAAQS as expeditiously as practicable.
 	The 2014 deadline for compliance with the limits on annual NOX and annual SO2 emissions is coordinated with the April 2015 maximum attainment deadline for areas that received the maximum 5-year extension of the 5-year attainment deadline for the 1997 PM2.5 NAAQS (taking into account the need for reductions by 2014 to demonstrate attainment by April 2015).  This 2014 compliance deadline is also consistent with December 2014 attainment deadline (5 years from designation, in the absence of an extension) for areas designated nonattainment for the 2006 PM2.5 NAAQS.  Areas unable to meet this 2014 deadline may seek a maximum 5-year extension to 2019.
 	In addition, the 2012 compliance deadline for the first-phase of annual NOX and annual SO2 emission reductions will assure the reductions are achieved as expeditiously as practicable.  EPA established the interim 2012 compliance deadline for annual NOX and annual SO2 reductions because a significant number of reductions can be achieved by 2012.  However, given the time needed to design and construct scrubbers at a large number of facilities, EPA believes the 2014 compliance date is as expeditious as practicable for the full quantity of SO2 reductions necessary to fully address the significant contribution to nonattainment and interference with maintenance.  Requiring reductions in transported pollution as expeditiously as practicable, as well as within maximum deadlines, helps to promote attainment as expeditiously as practicable.  This is consistent with statutory provisions that require states to adopt SIPs that provide for attainment as expeditiously as practicable and within the applicable maximum deadlines.
b. Public comments and EPA responses.
      EPA received numerous comments on the proposed compliance dates.  A number of commenters supported EPA's compliance schedule and rationale.  Other commenters supported extending the compliance deadlines to later dates.
 	Many commenters questioned the technical feasibility of achieving the required reductions by the 2012 and 2014 dates.   EPA's responses to those comments are discussed below in section VII.C.2.
 	Other commenters provided policy and legal arguments for allowing states to develop SIP alternatives to the FIP, and to build time for that SIP development and review process into the compliance schedule.  For example, some commenters asserted that the requirement in the CAA for providing reductions "as expeditiously as practicable" must be balanced with CAA provisions allowing states to develop state implementation plans prior to EPA imposing FIPs.  EPA responses to those comments are discussed in section X.
 	Some commenters suggested that EPA had the ability to leave CAIR in place for a transition period, and by doing this EPA could allow for a longer compliance period for this rule.  EPA does not believe it would be appropriate, in light of the Court's decision in North Carolina, to establish a lengthy transition period to the rule that will replace CAIR.  Although the Court decided, on rehearing, not to remand CAIR without vacatur, the Court stressed its prior decision that CAIR was deeply flawed and EPA's obligation to remedy those flaws.  North Carolina, 550 F.3d 1176. Although the Court did not set a definitive deadline for corrective action, the Court took care to note that the effectiveness of its opinion would not be delayed "indefinitely" and that petitioners could bring a mandamus petition if EPA were to fail to modify CAIR in a manner consistent with its prior opinion.  Id.  Given the Court's emphasis on remedying CAIR's flaws expeditiously, EPA does not believe it would be appropriate to establish a lengthy transition period to the rule which is to replace CAIR.
 	As relates to PM2.5, EPA received a number of comments on its proposal to include a 2012 deadline to ensure that emission reductions needed to reduce PM2.5 be achieved "as expeditiously as practicable."  Some commenters supported EPA's 2012 deadline.   Other commenters believed that it was unnecessary and unwarranted for EPA to impose emission reduction requirements in advance of the 2014 attainment date.  In light of the 2014 five-year attainment date for the 2006 PM2.5 NAAQS (with a possible extension to 2019), and the possible extension to April 2015 for the 1997 PM2.5 NAAQS, these commenters believed EPA's 2012 emission reduction requirements for annual PM2.5 and NOX were not necessary.  EPA disagrees with these commenters, for a number of reasons.  First, EPA notes (supported by commenters) that there is a clear statutory obligation to attain "as expeditiously as practicable."  Second, EPA notes that there are feasible reductions available by 2012.  Third, EPA believes that the substantial health and environmental benefits achieved by the rule underscore the importance of achieving the reductions as soon as possible.
 	With respect to ozone, some commenters noted that the proposed rule required ozone reductions by 2012 for states impacting areas which EPA's analysis shows will attain the 1997 ozone NAAQS by 2014 without further controls.  Those commenters questioned the importance of getting reductions in such states and whether the 2012 deadline is necessary.  EPA disagrees with those comments.  Except for Houston all ozone areas within the region addressed by this rule have attainment dates no later than 2013.  In effect, this means that emission reductions needed to attain the 1997 ozone NAAQS must be in place by the 2012 ozone season.  EPA believes that if there are reductions available by 2012, and those emission reductions have in fact been identified, it is appropriate and necessary to ensure that those reductions are in place.
2. Compliance and Deployment of Pollution Control Technologies
      The power industry will undertake a diverse set of actions to comply with the Transport Rule at the start of 2012 and another set of actions when companies in Group 1 states comply with more stringent SO2 budgets at the start of 2014.  In 2012, the industry will largely meet the rule's NOX requirements by:  operating an extensive existing set of combustion and post-combustion controls on fossil fuel-fired generators; dispatching lower emitting units more often; and installing and operating a limited amount of relatively simple NOX pollution controls in states not previously subject to CAIR.  For the SO2 requirements, EPA anticipates at a minimum that coal-fired generators will operate the substantial capacity of advanced pollution controls already in place or scheduled for 2012 use; some units will also elect to burn lower-sulfur coals, and the fleet will increase dispatch from lower-sulfur-emitting units as well as from natural gas-fired generators.  EPA provides a more detailed explanation below of how fuel switching to lower sulfur coals factored in to the design of the final Transport Rule.
	By 2014, EPA's budgets under the Transport Rule will sustain previous NOX and SO2 reductions as well as account for reductions from additional advanced NOX and SO2 controls that are driven by other state and federal requirements.  In addition to these reductions, companies in Group 1 states are also projected to add a limited amount of advanced SO2 controls in 2014 that will be discussed below.
      EPA's expectations are supported by the IPM analysis reported in this rule's Regulatory Impact Analysis (see Chapter 7).  Notably, since EPA has established a cap-and-trade control system for lowering NOX and SO2 emissions,  individual owners and operators of covered units have some flexibility in meeting the program's requirements as needed  and are free to find alternative ways to comply.  The RIA clearly shows a viable known pathway for owners and operators to comply at reasonable costs, although it is not the only compliance pathway possible under this flexible regulation that could deliver the emission reductions required under the rule.  Notably, by 2014 and beyond, the power industry may also augment the projected compliance efforts with programs aimed at improving energy efficiency.
      Table VII.C.2-1 shows EPA's projection of the amount of existing coal-fired generating capacity in gigawatts (GW) that may retrofit various systems for compliance with this rule.

Table VII.C.2-1 Projected Potential Air Pollution Control (APC) Retrofits for Transport Rule
                           Capacity retrofitted by:
                                    Wet FGD
Dry FGD
                                      DSI
                                      SCR
                             LNB/OFA Improvements
                                January 1, 2012

                                     10 GW
                                January 1, 2014
                                    5.7 GW
                                     0.2 GW
                                    3.0 GW
                                     0 GW

      EPA received proposal comments expressing a concern about the feasibility of deploying retrofit APC technologies in the time frames available between the final date of this rule and the compliance dates. As discussed below, EPA believes that it is feasible for the electric power sector and its APC supply chain to either make most of the projected retrofits in time to meet the 2012 and 2014 compliance deadlines, or to comply by other means.
a. 2012 Power Industry Compliance
      EPA's analysis of emission reductions available in 2012 assumes year-round operation of existing post-combustion pollution controls in states covered for PM2.5 and ozone-season operation of NOX post-combustion controls in states covered for ozone.  EPA also modeled emission reductions available in 2012 at the $500/ton threshold for SO2, $500/ton for annual NOX, and $500/ton for ozone-season NOX.
      For SO2, EPA believes that reductions associated with the following methods of control are available and will be used as compliance strategies to meet the 2012/2013 budgets: 1) operation of existing controls year-round in PM2.5 states, 2) operation of scrubbers that are currently scheduled to come online by 2012, 3) some sources switching to lower-sulfur coal (see Section C that follows), and 4) changes in dispatch and generation shifting from higher emitting units to lower emitting units.  EPA modeling and selection of a $500/ton cost threshold includes all existing and planned controls operating year round (items 1 and 2).  It also reflects an amount of coal switching and generation shifting that can be achieved for $500/ton.  This set of expected actions was confirmed in the detailed modeling of EPA's final remedy in the RIA and can be reviewed there.
      For NOX, EPA has also concluded that it is appropriate to require reductions through a limited amount of combustion control improvements, and in some cases, retrofits such as low-NOX burners (LNB) and/or overfire air (OFA). EPA recognizes that the 6-month time frame between rule finalization and start of the first compliance period would not allow for the installation of a major post-combustion NOX control such as selective catalytic reduction (SCR).  Assumed improvements and retrofits for the January 1, 2012 deadline for NOX therefore only involve the much simpler LNB/OFA control modifications or installations. Alternatively, some plant owners might choose to achieve NOX reductions in a similar time period through an even simpler retrofit - selective non-catalytic reduction (SNCR).
      Although the improvements, and in some cases, installation of combustion controls would be an economic means of achieving emission reductions, these specific controls are not required for compliance purposes under the final Transport Rule remedy.  Individual sources may comply through other measures (such as purchasing additional allowances) in the event that it takes more than 6 months for installation of a given combustion control.  The vast majority of covered sources already have combustion controls installed; therefore, the NOX reductions associated with these incremental control improvements and installations are small.
      Based on the Transport Rule's geography, EPA estimates that approximately 10 GW of coal-fired units may improve, and in some cases, install LNB/OFA specifically in reaction to the Transport Rule NOX caps.  EPA reflects the effects of these installations in the 2012 annual and ozone-season NOX budgets, which would yield  reductions of approximately 28,000 tons of annual NOX and 14,000 tons of ozone-season NOX.  EPA assumes these controls are cost effective at $500/ton and that they should be incentivized through budgets given the 2013 attainment deadline for ozone areas classified as "serious."  Once installed, LNB/OFA operates any time the boiler is fired and thus yields NOX reductions beyond the ozone season alone.
      In the proposal's LNB technical support document, EPA observes that LNB and/or OFA installations, burner modifications, or other NOX reduction controls would likely have to be installed during fall 2011 or spring 2012 outages in order to achieve significant reductions for 2012. While this 6-month schedule is aggressive, industry has shown that it can be met. For example, Limestone Electric Generating Station Unit 2, an 820 MW tangentially-fired lignite unit, was retrofitted with Foster Wheeler's Tangential Low NOX (TLN3) system in less than six months, including engineering, fabrication, delivery and installation.  Harlee Branch Unit 4, a 535 MW cell-fired unit, was retrofitted with Riley Power's low-NOX Dual Air Zone CCV burners on a similar schedule. Although such 6-month schedules can be achieved on some units, under favorable circumstances, historical projects suggest a more typical schedule would be 12 to 16 months for the contractor's portion of the work.  A plant owner's project planning and procurement work in advance of a contract award would typically involve several additional months. On the other hand, there are other approaches that can also be implemented in a short time frame to achieve significant NOX reduction. As mentioned above, relatively simple SNCR systems can be installed quickly; and the re-tuning or upgrading of existing combustion control systems can often provide significant NOX reductions and can be performed quickly.
      As stated above, EPA believes that LNB/OFA modifications or retrofits would be possible during the 6-month interim between rule signature and the start of the first compliance period, particularly for those "early movers" who have initiated LNB projects based on the proposed rule. However, even if every affected unit from the analysis delayed LNB modification or installation until the beginning of the 2012 ozone season (10 months from a June 30, 2011 signature), the emissions consequence would be limited to less than 1 percent of most states' annual NOX budgets, reaching at most 5 percent of only one state's annual NOX budget.  In light of this limited consequence and the supporting material above, EPA includes LNB-driven NOX reductions in both annual and ozone-season NOX budgets for 2012.
b. 2014 Power Industry Compliance
      EPA projects that compliance with 2014 requirements for NOX will result largely from operation of existing and future controls required by state and other federal requirements, as well as the appropriate dispatch of the electric generation fleet. EPA does not project additional NOX pollution control retrofits aside from about 10 GWs of combustion control improvements or retrofits projected for the 2012 compliance period.  To comply with the rule's SO2 requirements, EPA projects that the power industry will rely on existing controls, operate newly installed advanced controls necessary for other binding state and federal requirements, rely more on relatively lower sulfur coals, and dispatch lower-emitting generation units.  In Group 1 states, industry is projected to increase switching to lower sulfur coals and install a limited amount of additional scrubbers and other advanced pollution control technology.   EPA's assessment of the industry's ability to install SO2 pollution controls in 2014 and undertake the projected coal switching follows below.
      EPA's modeling of least-cost compliance with the state budgets under the Transport Rule projects approximately 5.9 GW of FGD systems and lesser amounts of other technologies will be retrofitted by 2014 for compliance with the Transport Rule. EPA's schedule assumptions for these larger more complex projects were developed in an earlier study and mentioned in the proposal: 27 months for retrofitted wet FGD and 21 months for SCR.  Note that a dry FGD system, due to its relatively simpler configuration and lesser cost, would typically take somewhat less time to retrofit than wet FGD.
      As discussed below, EPA believes that its schedule assumptions remain reasonable expectations for sources that have completed most of their preliminary project planning and can quickly make commitments to proceed. These schedules do not include the extensive time that some plant owners might spend in making a decision on whether or not to retrofit. They do include the time needed to make a final confirmation of the type of technology to be used at a particular site, to prepare bid requests, award contracts, perform engineering, obtain construction and operating permits (in parallel with project activities), perform construction, tie-in to the existing plant systems, and perform integrated systems testing.
      EPA received comments on the proposed rule indicating that some past single-unit APC retrofits had considerably longer schedules, with a few exceeding 48 months. EPA engineering staff have extensive experience with power plant and APC system design, construction, and operation. Based on that experience, EPA can observe that in the absence of a compelling deadline or major economic incentive, many large project schedules are considerably longer than necessary. Given further observations as explained below, EPA believes it reasonable to expect that almost all future APC retrofits can be completed far more quickly than they were in recent history.
      EPA's perspective on this matter derives in part from a comparison of longer APC schedules (as provided by some commenters) to the project schedule for an entire new coal-fired unit, including its APC systems. Springerville Unit 3, for example, is a 400 MW coal-fired unit that became operational in July 2006, some 33 months after the turnkey engineering-construction contractor was given a notice to proceed with engineering.  Springerville was clearly on an accelerated schedule, as its original planned schedule was about 38 months.  Another example is Dallman Unit 4, a high-sulfur bituminous coal-fired 200 MW unit with SCR, fabric filter, wet FGD, and wet ESP. Dallman Unit 4 was first synchronized in May 2009, several months ahead of schedule, and about 36 months after its turnkey contractor placed initial major equipment orders. The main point here is that recent APC project schedules, and those of large complex power projects, can be significantly accelerated. Because the scope and complexity of the work involved for an entire new coal unit and its APC systems is perhaps five times greater than that of a retrofit wet FGD system alone, EPA believes it is reasonable to expect that even the most complex retrofit APC project can be significantly accelerated as well. Additional factors are discussed below that further support the feasibility of installing by 2014 the 5.9 GW of FGD retrofits projected for this rule.
      Although IPM modeling provides reliable estimates on a regional basis, and cannot be as accurate at the level of individual plants or units, it is informative and relevant to consider IPM's plant level projections in this case. Although the IPM-projected retrofits named below may not actually occur, IPM projects that they would be economic and would allow industry to meet the tighter SO2 emission standards in Group 1 states in 2014. EPA notes that the owners of the particular plants mentioned below (Duke Energy, AEP, Edison International) are large, experienced, versatile utilities who have done considerable advance planning and should also have above-average flexibility to comply with state budgets across their fleets. EPA would expect such owners to have relatively little difficulty in permitting and financing FGD retrofits.
      Of the Transport Rule-related FGD retrofits, 0.2 GW is projected to use dry FGD, which EPA expects to be simpler and quicker installations than those with wet FGD.  Half of the 5.9 GW (Muskingum, Rockport) has already been committed under consent decrees to add controls or retire; and EPA reasonably believes that significant preliminary project planning work has already been done for those projects. An additional 1,200 MW (Homer City) had completed project planning and was ready to proceed in 2007, before putting the project on hold. The latter plant is now facing EPA legal action and the possibility of a required expeditious FGD retrofit. Thus, of the 5.9 GW of projected FGD retrofits resulting from this rule, nearly 75 percent appears to be in good position for an early start of construction, and over 3 GW of that would be bringing forward already committed compliance start dates.
      Any of the above mentioned potential retrofits or any other unit that might choose to retrofit FGD for a January 2014 compliance date will likely have to use various methods to accelerate the project schedule. Such methods could include the use of parallel permitting, overtime and/or two-shift work schedules during construction, and 5- or 6-day work weeks instead of the 4-day x 10-hour schedules often used to minimize cost when time is not of the essence. Increased use of offsite modularization and pre-fabrication of APC components could also shorten schedules and reduce job hours.
      EPA believes that the January 1, 2014 compliance starting date is as expeditious as practicable for the sources installing large, complex control systems. The following additional observations support EPA's expectation that the limited 5.9 GW of FGD retrofits can be realized in the 30 month interim between rule signature and the start of 2014:
      ●  	There are documented instances of large, complex wet FGD retrofits being deployed in less than 30-months (excluding the time for owners' project planning). Examples are Killen Station Unit 2, and Asheville Unit 1.
      ●  	In 2009 the APC supply chain deployed more than six times more GW capacity of FGD and SCR controls than the 5.9 of FGD that would be deployed by 2014 under this Rule.
      ●  	The APC supply chain has seen a 2-year decline in deployments since its peak in 2009, but in 2011 is nonetheless putting into service about three times more GW capacity of FGD and SCR controls than the 5.9 of FGD that would be deployed under this Rule.
      ●	Because the supply chain has been in decline, but remains quite active, there are now adequate supply chain resources available that can be quickly reengaged to support a rapid deployment of 5.9 GW of FGD.
 	EPA recognizes that the installation of any amount of scrubbers in this short time frame will require aggressive action by plant owners and that the owners who can meet this schedule will already have done their project planning and will be ready to place orders. An example of such "early movers" was seen in the power sector's anticipation of CAIR. EPA data indicate that solely CAIR-driven FGD and SCR deployments of about 6 GW occurred within two and one-half years after CAIR's finalization in mid-2005, showing that at least 20 percent of the total CAIR-only controls effort through a 2010 compliance date was sufficiently planned for installation to start before or immediately upon finalization of the rule.  EPA reasonably expects that similar advance planning has already been done for units that would retrofit under this rule.
      In the event that a particular control installation requires additional time into 2014 to come online, EPA believes compliance would not be jeopardized given the ability of sources to purchase allowances during that time.  This approach could be supported by some sources with FGD that have the ability to increase their SO2 removal above historic rates, perhaps through relatively low cost upgrades to improve scrubber effectiveness, or by operating scrubbers at higher chemistry ratios.  The ability of sources to temporarily or permanently substitute dry sorbent injection (DSI) for FGD serves as another backstop for any feasibility issues regarding FGD.  Note that the updated modeling for this rule projects the addition by 2014 of about 3 GW of DSI for SO2 control using trona or other sorbent.  DSI is a relatively low capital cost technology that readily can be installed in the time frame available for compliance.[,]
      It should also be noted that most APC retrofits will involve a source outage for final "tie-in" of retrofitted systems to existing systems, during which time emissions from the affected units are zero.  For some sources, the duration of this tie-in outage may effectively extend the deadline by which all of the projected emission reductions need to occur.
      Although EPA believes that installation of 5.9 GW of FGD at facilities by January 1, 2014 is feasible, EPA also conducted an IPM sensitivity analysis to examine a scenario in which FGD retrofitting by 2014 is not allowed.  Results of EPA's "no FGD" analysis indicate that if the power industry were subjected to the requirements of this rule without an FGD retrofit option for compliance, covered units would still be able to meet the Transport Rule requirements in every state while respecting each state's assurance level.  (See the docket to this rulemaking for the TR No FGD in 2014 Scenario Final IPM run.)
      In this scenario without the availability of new FGD by 2014, sources in covered states complied with the Transport Rule budgets by using moderate additional amounts of DSI retrofits, switching to larger shares of sub-bituminous coal, and dispatching larger amounts of natural gas-fired generation in lieu of the FGD retrofits that are projected as being most economic under modeling of the Transport Rule remedy.  Because new FGD capacity is included in EPA's projection of the least-cost set of SO2 emission reductions required in Group 1 states, the "no FGD" sensitivity scenario did project higher system costs, although these costs were still substantially lower than the remedy EPA modeled in the Transport Rule proposal.
      The "no FGD" analysis indicates that while the ability of Group 1 states to meet their 2014 SO2 budgets is facilitated by FGD retrofits, they are by no means required, nor is Transport Rule compliance jeopardized by their absence.  Even under a scenario in which sources fail to complete FGD retrofits by 2014, sources in the affected states would have other compliance options available at reasonable cost to meet the state's budget requirements.  This analysis shows that Group 1 states would be able to comply with their 2014 SO2 budgets by relying on other emission reduction opportunities that do not require FGD retrofits.  EPA analysis confirms that those alternatives are feasible both in terms of cost and timing.
      Finally, EPA recognizes that, when finalized later this year as currently scheduled, the Mercury and Air Toxics Standards (MATS) will require significant retrofit activity at covered sources in the power sector with a 2015 compliance date for that rule.  EPA's projections of retrofit activity under the final Transport Rule are highly compatible with its projections of retrofit activity under the proposed MATS (which included the proposed Transport Rule in its baseline).  EPA therefore anticipates that the Transport Rule's projected retrofit activity will not only be the least-cost compliance pathway to meeting state budgets in 2014 but will also accelerate emission reductions subsequently required by the effective date of MATS.  The final Transport Rule's projected 2014 retrofit installations will also further incentivize the power sector to ramp up its retrofit installation capabilities to achieve broader deployment of the projected pollution control retrofits under the proposed MATS.
      Considering all the reasons given above, EPA has concluded that the 2014 requirements for SO2 emissions in the states covered by the Transport Rule are reasonable and can be met by the power industry by a variety of means.
c. Coal Switching for SO2 Compliance in 2012 and 2014
      Coal switching is another mechanism which can be used along with operating pollution controls in 2012 for compliance.  It will be a complementary activity by many coal-fired units alongside of operating pollution controls and the addition of more scrubbers and DSI in 2014.
      In the proposal, EPA noted that coal switching could serve as a compliance mechanism for 2012. EPA requested comment on the reasonableness of EPA's assumption that coal switching will have relatively little cost or schedule impact on most units.  EPA received substantial comment suggesting that the coal switching and coal blending projected by EPA modeling are not feasible for all units, and that, if feasible, would often incur a cost through the derating of the unit associated with the switch to a lower sulfur coal or coal blend.  Additionally, sources indicated that coal switching by 2012 would not always be possible in the six month window between final rule signature and start of compliance.  These feasibility concerns stemmed from restrictions included in existing coal supply contracts and from boiler design constraints that may hinder coal switching within a six month window.
      EPA agrees with these concerns and revised its IPM modeling to limit coal switching capability in 2012 for particular units that may have trouble switching coals or coal blends in a six month time frame.  A cost adder was also included in the IPM modeling for coal switching to capture the potential cost burden of deratings that might accompany switching to a very low sulfur subbituminous coal or coal blend.
      A particular commenter concern regarding switching to lower sulfur within the eastern bituminous coals related to a possible impact on the performance of a cold-side electrostatic precipitator (ESP).  Some ESPs that operate at acceptably high collection efficiency when using a high- or medium-sulfur bituminous coal may experience some loss in collection efficiency when a lower sulfur coal is used.  Whether this occurs on a specific unit, and the extent to which it occurs, would depend on the design margins built into the existing ESP, the percentage change in coal sulfur content, and other factors.  In any case, industry experience indicates that relatively inexpensive practices to maintain high ESP performance on lower sulfur bituminous coals are available and can be used successfully where necessary.  These include a range of upgrades to ESP components and flue gas conditioning.  EPA therefore assumes that it will not be necessary for units that switch from higher to lower sulfur bituminous to make a costly replacement of the ESP.
      Coal switching as a SO2 compliance option might also include switching from bituminous to subbituminous coal.  EPA's analysis does not assume that a unit designed for bituminous can switch to (very low sulfur) subbituminous coal unless the unit's historical data demonstrate that capability in the past.  EPA assumes that units with that demonstrated capability have already made any investments needed to handle a switch back to the use of subbituminous coal at a similar percentage of its heat input as in the past.  For IPM analysis in the final rule EPA also introduced a coal switching option that assumes that units can increase a historically low percentage use of subbituminous to a "maximum" level, if economic.  This option includes an appropriate derate in output, increase in heat rate, and additional capital and operating costs.  Details of this and other IPM updates for this rule are provided in the IPM Modeling Documentation in the docket for this rulemaking ("Documentation Supplement for EPA Base Case v.4.10_FTransport  -  Updates for Final Transport Rule").
D. Allocation of Emission Allowances
      Under the final rule, EPA distributes a number of SO2, annual NOX, and ozone-season NOX emission allowances to covered units in each state equal to the SO2, annual NOX, and ozone-season NOX budgets for those states.  These budgets are addressed in section VI.D of this preamble.  This section discusses the methodology EPA uses to allocate allowances to covered units in each state.
      As discussed later in section VII.D.2, EPA is setting aside a base 2 percent of each state's budgets for allowance allocations for new units, with 5 percent of that 2 percent, or 0.1 percent of the total state budget being set aside for new units located in Indian country.  To this base 2 percent, EPA is setting aside an additional percentage on a state-by-state basis, ranging from 0 to 6 percent (yielding total set asides of 2 percent to 8 percent), for units committed to be built. The remainder of the state budget is allocated to existing units.  Tables VI.D.-3 and VI.D.-4 in this preamble show the SO2, annual NOX, and ozone-season NOX budgets for each covered state (without the variability limits).  In allocating allowances to existing and new units, EPA distributes four discrete types of emissions allowances for four separate programs: SO2 Group 1 allowances, SO2 Group 2 allowances, annual NOX allowances, and ozone-season NOX allowances.
      In the SO2 Group 1 and SO2 Group 2 programs, each SO2 allowance authorizes the emission of one ton of SO2 in that vintage year or later and is usable for compliance only in the program for which the allowance was issued.  In the annual NOX program, each annual NOX allowance authorizes the emission of one ton of NOX in that vintage year or later in that program.  In the ozone-season NOX program, each ozone-season NOX allowance authorizes the emission of one ton of NOX during the regulatory ozone season (May through September for this final rule) in that vintage year or later for that program.
      In each of the four trading programs, a covered source is required to hold sufficient allowances (issued in the respective trading program) to cover the emissions from all covered units at the source during the control period.  EPA assesses compliance with these allowance-holding requirements at the source (i.e., facility) level.
      This section explains how, in this final rule, EPA allocates a state's budget to existing units and new units in that state.  This section also describes the new unit set-asides and Indian country new unit set-asides in each state, allocations to units that are not operating, and the recordation of allowance allocations in source compliance accounts.
1. Allocations to existing units
      This subsection describes the methodology EPA will use in the FIPs finalized in this action to allocate to existing units.  The same methodology will be used to allocate allowances to existing units for all four trading programs.
      For the reasons explained below, EPA has decided to base allocations made under the FIPs on historic heat input, subject to a maximum allocation limit to any individual unit based on that unit's maximum historic emissions.  This methodology gives each existing unit an allocation equal to its share of the state's historic heat input for all the covered units in the program, except where that allocation would exceed its maximum historic emissions; this methodology constrains the heat input-based allocations from exceeding any unit's maximum historic emissions.  Further detail on the implementation of this approach is provided in section VII.D.1.c below as well as in the Allowance Allocation Final Rule TSD in the docket for this rulemaking.  All existing-unit allocations for 2012 will be made pursuant to the FIPs.  However, as described in section X, states may submit SIPs or abbreviated SIPs to use different allocation methodologies for allowances of vintage year 2013 and later.
a. Summary of allocation methodologies and comments
      EPA took comment on three distinct allocation methodologies for existing units.  The first  - - an emissions-based option - -  was presented in the original Transport Rule proposal (75 FR 45309).  The second and third  -  heat input option 1 and heat input option 2  -  were presented in a Notice of Data Availability (76 FR 1113).  EPA received numerous comments on all three options.
      i. Emissions-based allocation methodology
      The emissions-based option presented in the original Transport Rule proposal would base allowance allocations to existing units on each covered unit's calculated emissions "share" of that state's budget for a given pollutant under the Transport Rule.  The proposed rule stated that "for 2012, each existing unit in a given state receives allowances commensurate with the unit's emissions reflected in whichever total emissions amount is lower for the state, 2009 emissions or 2012 base case emissions projections.  In either case, the allocation is adjusted downward, if the unit has additional pollution controls projected to be online by 2012...For states with lower SO2 budgets in 2014 (SO2 Group 1 states), each unit's allocation for 2014 and later is determined in proportion to its share of the 2014 state budget, as projected by IPM" (75 FR 45309).
      Many commenters objected to this projected emissions allocation methodology.  Commenters offered two principle objections.  First, they argued EPA should not use unit-level model projections to allocate allowances.  Second, they argued the use of any emissions-based allowance methodology is improper.  Many of these commenters argued that instead of an emissions-based allocation methodology, EPA should use a heat-input-based allocation methodology.
      Commenters' objections to the use of unit level model projections focused primarily on the accuracy of such projections.  While many commenters supported the use of modeling projections in determining state emissions budgets, they argued that the unit-level model projections were not sufficiently accurate to use as a basis for allocating allowances to individual units.  Among other things, they argued that the modeling used for the proposal did not recognize certain non-economic factors that may cause individual units to operate differently than the model projects.  Commenters also argued that EPA's modeling does not capture all up-to-date contracts and other economic arrangements made at the unit-level which may affect operational decision-making.  Some of these commenters continued to support the use of an emissions-based allocation approach, but urged EPA to use more up-to-date and specific unit-level data in its modeling projections.  Others opposed the use of any emissions-based allocation approach.
      EPA acknowledges that the model may not, at this time, capture all relevant operational decision factors for each individual unit.  EPA also recognizes that there are unit-level details of operational decision-making and economic arrangements (such as certain contracts for electricity sales) that are private and thus unavailable to EPA on an ongoing basis for modeling purposes.  EPA believes these potential omissions would not have a significant impact on EPA's determination of significant contribution at the state level; however, EPA recognizes they could conceivably have a significant impact on projections at the individual unit level.  EPA thus agrees with commenters that the unit-level emissions projections from its modeling may not reflect all possible operational decisions at a given unit and are therefore not an appropriate proxy measure to use as a basis for allocating allowances to individual units.
      Many commenters also argued that, even if the emissions projections could be adjusted to capture all known and up-to-date unit-level operational factors, EPA should not use any emissions-based allocation approach.  They argued that an emissions-based approach should not be used because it is not fuel-neutral.  That is to say, the type of fuel consumed significantly affects the emissions from, and therefore the allocation to, a given unit under an emissions-based approach.  Commenters argued that an approach that is not fuel-neutral effectively awards higher-emitting units.  Commenters also argued that a projected emissions-based approach should not be used because it is not control-neutral.  In other words, whether or not a unit has installed controls would significantly affect the allocation for a given unit under an emissions-based approach.  Under an emissions-based approach, controlled units receive significantly fewer allowances than uncontrolled units.  Such an approach, commenters pointed out, effectively penalizes sources who have taken action to reduce emissions.
      EPA acknowledges that an emissions-based approach would not be fuel-neutral or control-neutral.  EPA notes that the D.C. Circuit rejected the fuel adjustment factors that were used in CAIR to adjust state budgets based on the type of fuel burned at each covered unit.  North Carolina, 531 F.3d 918-21 (rejecting use of fuel adjustments in setting state NOX budgets).  While the proposal's allocation methodology did not explicitly adopt "fuel adjustment factors" for allocation purposes, EPA recognizes that an emissions-based allocation methodology effectively advantages or disadvantages units based on the type of fuel they combust.
      In addition, several commenters argued that the proposal's emissions-based methodology would inappropriately reward the highest emitters under the program with more allowances than their lower-emitting counterparts would receive.  EPA acknowledges that such a methodology would allocate more allowances to units whose emissions make up a larger share of the proposed Transport Rule programs' state budgets.  EPA notes that because any allocation patterns under the Transport Rule FIPs would be established in advance of covered sources' compliance decisions (i.e., decisions regarding how much to emit under the programs), covered sources cannot be "rewarded" by adjusting their future emissions.  However, EPA notes commenters' observations that the proposal's methodology would reduce allocations to units that previously installed pollution control technology or invested in cleaner forms of generation in anticipation of CAIR.  EPA concluded in review of these comments that the proposed Transport Rule's allocation methodology unintentionally yielded this distributional outcome.  EPA therefore considered alternative allocation methodologies described below.
      A substantial portion of the commenters who objected to the proposal's emissions-based allocation option urged EPA to consider historic heat input based approaches.  EPA agreed it should accept comment on the use of historic heat input-based approaches and published a NODA to provide an opportunity for comment on two specific heat input options and the allocations that would result from application of those options to the proposed Transport Rule state budgets.
      ii.  Heat input allocation option 1
      The first heat input option presented by EPA in the NODA ("Option 1") allocates allowances to units based solely on their historic heat input.  Under this option, EPA would establish a 5-year historic heat input baseline for each covered unit and allocate allowances to sources at levels proportional to the each unit's share of the total historic heat input at all covered units in that state.
      Numerous commenters supported the use of a heat-input based allocation methodology.  These commenters stated that basing allocations on historic heat input has the following advantages over the proposal's emissions-based allocation methodology:
      (A) For certain types of units, historic heat input data may offer a better representation of unit-level operation than model projections of unit-level emissions; furthermore, for all units, historic heat input is typically represented by quality-assured data reported by sources from continuous emissions monitoring systems, which strengthens its accuracy.
      (B) Historic heat input data are generally fuel-neutral in that they do not generally yield higher allocations for units burning or projected to burn higher emitting fuels.
      (C) Historic heat input data are generally emissions-control-neutral in that they do not generally yield reduced allocations for units that installed or are projected to install pollution control technology.
      Many commenters also argued that a heat input-based allocation methodology should be used because, unlike the proposal's emissions-based methodology, a heat-input based methodology would be generally fuel-neutral and control - neutral and would rely on unit-level quality-assured data instead of on modeling projections.
      Several commenters expressed support for specific aspects of heat input option number one.  From a technical standpoint, commenters noted that heat input option 1 relied on the highest-quality and most transparent data EPA had provided as a basis for allocating allowances under the Transport Rule programs.  They argued that the calculation methodology for heat input option 1 is more readily re-created and understood by sources than either the proposal's methodology or EPA's application of the "reasonable upper-bound capacity utilization factor and a well-controlled emission rate" in heat input option 2 (described in greater detail below).  They also pointed out that it is similar to methodologies used in previous trading programs, such as the NOX Budget Trading Program (see 40 CFR 96.42(a) & (b) (calculating each existing EGU's allocation by multiplying each unit's historic heat input by 1.5 lb/mmBtu)).  In addition, commenters supported the reliance of heat input option 1 on continuous emissions monitoring system (CEMS) data that are reported to EPA and certified by the source's designated representative (DR) as accurate and complete.  In addition, many commenters supported EPA's use of historic data without further transformation by any calculation factors created by EPA.
      From a policy perspective, commenters highlighted the fuel neutrality and emissions-control neutrality aspects of heat input option 1.  They noted that this option does not, in contrast to the proposal's emissions-based methodology, penalize a source, through a reduced allowance allocation, for having chosen a generation technology or emissions control technology that was more favorable to public health and the environment.  EPA agrees with these observations.  The allocation pattern associated with this option does not advantage or disadvantage units based on either the fuel consumed or the presence or absence of a pollution control technology.  In this respect, it is a neutral approach that does not "reward" high-emitting units or "penalize" low-emitting units, including, for example, those units on which pollution control technology was installed in anticipation of CAIR.
      EPA agrees with the aforementioned arguments from these commenters regarding the technical and policy merits of this heat input-based allocation methodology.  EPA believes that the quality-assured heat input data reported by EGUs under its programs are among the most detailed and sound unit-level data accessible by EPA.  EPA believes the calculation of any individual unit's share of this historic heat input data is a straightforward, clear, and simple calculation to perform, such that EPA's calculated allowance allocations under this approach can be relatively easily replicated.
      EPA also agrees with commenters that such data has previously supported allowance allocation procedures for highly successful program implementation of the Acid Rain Program (ARP) and the NOX Budget Trading Program (NBP).  Notably, Congress chose a heat input-based allocation approach when authorizing the ARP in title IV of the Clean Air Act, suggesting that Congress viewed heat input as a reasonable basis for allocation.  Additionally, EPA's selection of a heat input-based approach for the NBP was not legally challenged, implying that stakeholders generally saw a heat input-based approach as reasonable.
      EPA also agrees with comments observing that allocations made under this heat input approach do not advantage or disadvantage units based on their choice of fuel combustion or pollution control technology and that allocations under this approach would thus be "fuel-neutral" and "control-neutral."  EPA also agrees with commenters that unlike the proposed rule's emissions-based methodology, this heat input methodology does not yield lower allocation to units that reduced emissions in advance of the Transport Rule relative to units that did not make such emission reductions.
      Other commenters objected to the use of a heat-input based allocation methodology.  These commenters argued that the allocation pattern associated with a heat-input allocation methodology would yield "windfall profits" -- in the form of allowance allocations greatly in excess of likely emissions -- for certain units, particularly with regard to SO2 allowance allocations for units combusting natural gas.  EPA disagrees with the characterization of the excess allowances as "windfall profits."  Allocations based on heat-input alone are fuel-neutral and control-neutral.  The characterization of the heat-input allocation methodology as creating "windfall profits" for any unit is based on the assumption that all units should be allocated allowances based on emissions, not heat input.  In arguing the heat-input approach creates a "windfall" for some units, commenters are assuming that the allocation of allowances above a unit's projected emissions constitutes a "windfall"  - - a conclusion EPA does not accept.  EPA believes that under market-based regulatory programs, it is appropriate to base initial allowance allocations on a neutral factor and allow the market to determine the least-cost pattern of emission reductions in each state to achieve the reductions that address the state's significant contribution and interference with maintenance under the final Transport Rule programs.  EPA disagrees that future allowance transactions (following a neutral-factor initial allocation) in response to these market forces can be characterized as "windfall profits."  As explained above, EPA believes it is appropriate to allocate allowances based on a neutral factor.  Commenters appear to ask EPA, instead of allocating based on a neutral factor, to consider the unit-level distributional impacts of each allocation methodology and to select an allocation methodology on the basis of equity.  EPA does not believe it would be appropriate for the agency to pick an allocation methodology to achieve any particular distributional outcome as such considerations are not related to the statutory mandate of CAA section 110(a)(2)(D)(i)(I).  Instead, EPA believes it is appropriate to allocate allowances to sources covered by its trading programs based on a neutral factor.  Furthermore, CAA section 110(a)(2)(D)(i)(I) requires prohibition of certain emissions within a state (i.e., a  state's significant contribution and interference with maintenance).  It does not direct EPA to use any particular methodology for allocating allowances under a trading program designed to ensure all such emissions are prohibited.  As such, EPA believes it is appropriate to allocate allowances based on a neutral factor representing fossil energy content used to produce electricity.  Detailed considerations of equity, as the D.C. Circuit reminded EPA, are not related to the statutory mandate of section 110(a)(2)(D)(i)(I). North Carolina, 531 F.3d 921.
      Some commenters objected to the use of a heat input-based approach by arguing that higher-emitting units would not receive an initial allocation sufficient to cover their emissions.  EPA does not believe it is reasonable to expect initial allocations to cover each unit's emissions under a trading program aimed at producing meaningful emission reductions.  In its administration of prior trading programs such as the ARP and the NBP, EPA has made initial allowance allocations using a heat input-based approach, and virtually all covered sources have successfully complied at the end of each compliance period by making cost-effective emission reductions, purchasing additional allowances through robust markets to cover emissions, or undertaking both types of activities.  EPA disagrees with commenters' arguments that allowance allocations should be used to compensate units with higher emissions.
      iii.  Heat input allocation methodology option 2
      The second heat input option presented by EPA for public comment also would use historic heat input but would apply a constraint to unit-level allocations under certain circumstances.  Specifically, under this option unit-level allocations would not be allowed to exceed what EPA determines, based on historic emissions and other factors, to be the units' "reasonably foreseeable maximum emissions."
      To apply this constraint, EPA first would determine whether the allocation to a unit under an unconstrained heat-input methodology would exceed that unit's maximum historic emissions of the relevant pollutant since 2003 "in order to reflect unit-level emissions before and after the promulgation of the CAIR" (76 FR 1115).  Using this baseline would enhance the neutrality of the maximum historic emissions data because it would capture the highest emissions of the unit during that period regardless of what fuels it combusted or what pollution control devices were installed and used at any particular time during that period.  In other words, a unit's allocation would not be reduced due to a recent decision to switch fuels or install pollution controls.
      Second, for this option, EPA then would adjust that maximum historic emissions data by applying a "well-controlled rate maximum," designed to place "a reasonably foreseeable maximum emissions level reflecting a reasonable upper-bound capacity utilization factor and a well-controlled emission rate that all units (regardless of the type of fuel they combust) can meet for the pollutant" (76 FR 1115).  This option would constrain certain units' allocations that, if based solely on historic heat input, would be determined by EPA to be "in excess of their reasonably foreseeable maximum emissions" under the Transport Rule programs (76 FR 1115).
      As noted above, commenters offered numerous arguments in favor of using a historic heat input approach.  These arguments apply equally to heat input option 1 and heat input option 2.  EPA also received numerous comments comparing the two heat input options presented.
      Many commenters preferred heat input option 1's reliance purely on historic data as compared with heat input option 2's reliance on that data modified by the application of EPA-determined "reasonable upper bound capacity factors" and "well-controlled emission rates." Commenters also criticized the complexity of these modification factors in heat input option 2.  While EPA believes both options represent viable approaches, the Agency agrees with commenters that the application of these factors increase the complexity of allocation determinations and would adjust unit-specific historic data by applying EPA-created factors generically determined for broad categories of units.
      Some commenters suggested that EPA's application of these modification factors could also represent legal vulnerabilities for the Transport Rule.  In particular, they were concerned that the capacity factors and well controlled emission rates presented as part of heat input option 2 could be perceived as arbitrary.  While EPA does not agree that these modification factors are arbitrary, the Agency does recognize that application of such EPA-created generic factors in determining unit-specific allocations increases the complexity of the allocation approach and raises issues regarding whether such generic factors are appropriately applied to each individual unit.
      iv. General comments on EPA's authority to allocate allowances
      Numerous commenters also noted that EPA has generally broad authority in selecting an allocation methodology under CAA sections 110(a)(2)(D)(i)(I) and 302(y).  EPA agrees with commenters that the Agency has broad discretion in this area.  Neither the CAA nor the D.C. Circuit Court's opinion in North Carolina specifies a particular methodology that EPA must use to allocate allowances to individual units.  CAA section 110(a)(2)(D)(i)(I) requires prohibition of emissions "within the state" that significantly contribute to nonattainment or interfere with maintenance and gives states broad discretion to develop a control program in a SIP that achieves this objective.  EPA has similarly broad discretion when issuing a FIP to realize this objective.  Moreover, while the definition of FIP in CAA section 302(y) clarifies that a FIP may include "enforceable emission limitations or other control measures, means or techniques (including economic incentives, such as marketable permits or auctions of emissions allowances)," this section does not require EPA to use any particular methodology to allocate allowances under a FIP trading program.  In light of this lack of direction in the CAA concerning allowance allocation, EPA has broad discretion to select an allocation methodology that is reasonable and consistent with the goals of CAA section 110(a)(2)(D)(i)(I).
      The body of public comment makes it clear that no allocation option could be deemed satisfactory from the perspective of all stakeholders.  Public comments from most states and industrial stakeholders with a substantial interest in how EPA allocates allowances under the Transport Rule FIPs expressed support for an historical heat input-based approach as opposed to the proposal's emissions-based approach.  Most commenters favored this historical heat input data basis as the most sound and offered technical data corrections, which EPA considered and generally used in the final rule.  EPA believes it is reasonable to select a heat input-based approach for the final Transport Rule because this approach is consistent with the rule's statutory objectives and has been found, when implemented in prior trading programs, to be a credible, workable allocation approach.
      b.  Final FIP Allocation Methodology
      After consideration of all comments, EPA decided to allocate allowances to individual units based on that units' share of the state's historic heat-input, but to ensure that no unit's allocations exceed that unit's historic emissions.  EPA decided to use the allocation methodology originally presented as heat input option 2, modified in response to public comments.  EPA decided to use heat input option 2 but without the application of the "reasonable upper-bound capacity utilization factor and a well-controlled emission rate" factors.  This allocation approach reflects the Agency's response to extensive public comment on the options presented in the proposed Transport Rule and subsequent NODAs and is a logical outgrowth of those actions.  EPA is using this approach to allocate allowances under the FIPs for all four trading programs.  Further details on the calculation and implementation of this approach are provided below in section VII.D.1.c and can also be found in the Allowance Allocation Final Rule TSD in the docket for this rulemaking.
      The principal reasons for this decision are:
         * EPA believes that existing-unit allowance allocation under the Transport Rule should not generally advantage or disadvantage units based on the selection of fuels consumed or of pollution controls installed at a given unit in anticipation of either the Clean Air Interstate Rule or the Transport Rule, i.e. fuel or control decisions taken from 2003 onward.  An approach that does not advantage or disadvantage units in this way avoids allocating in a way that would effectively penalize units that have already invested in cleaner fuels or other pollution reduction measures that will continue to deliver important emission reductions under this rulemaking.  The approach selected in the final rule generally does not penalize such units and is thus generally fuel-neutral and control-neutral in its allocation determinations.
         * EPA finds that the selected approach maximizes transparency and clarity of allowance allocations.  EPA has already made public the historic heat input and historic emissions data on which this approach is based, and its application to calculate unit-level allocations in each state under that state's emission budgets finalized in this Transport Rule can be relatively easily replicated.
         * EPA finds that quality-assured historic CEMS-quality data used to implement this approach represent the most technically superior data available to EPA at the time of this rulemaking for calculating unit-level allocations.  The selected approach relies on unmodified historic data reported directly by the vast majority of covered sources, whose designated representatives have already attested to the validity and accuracy of this data.  EPA agrees with commenters that allowance allocations should be based on quality-assured data to the maximum extent possible.  This approach uses the most accurate data currently available to EPA.
         * Heat-input based approaches were used to allocate allowances under both the NOX Budget Trading Program and the Acid Rain Program.  Allocation under these programs was readily and easily administered, and the programs achieved or exceeded their environmental goals.  The selected approach's use of heat input as a basis for allocations builds on prior legislative and administrative approaches to allowance allocations for trading programs.
         * EPA also finds that the selected approach's addition of a constraint to heat input-based allocations where such allocations would otherwise exceed a unit's maximum historic emissions is a reasonable extension of a heat input-based allocation approach.  The Transport Rule trading programs are established to achieve overall emission reductions in each covered state.  As a group, covered sources within each state must make the necessary reductions under these programs.  In light of each program's goal to reduce each state's overall emissions, it is logical and consistent with that goal that the starting point for each source under these programs  - - i.e., the initial allocations of shares of the state budget to covered units -- be an amount of allowances no greater than each unit's maximum historic emissions.  Under the trading programs, any source may emit a ton of SO2 or NOX for which it holds a corresponding allowance, which it may acquire either by initial allocation or by subsequent purchase, to the extent consistent with the assurance provisions (discussed elsewhere in this preamble) that ensure achievement of the requisite overall reductions  in each state.  Consequently, the initial allocations to the units at each source are the starting point for each source's efforts to comply with the allowance-holding and assurance provision requirements, but do not determine the source's strategies for compliance and ultimate level of emissions.  EPA believes that a starting point of unit-level heat input-based allocations constrained not to exceed each specific units' maximum historic emissions is reasonable and consistent with the program goals of reducing overall emissions in each state: each existing unit is allocated an amount that either reflects reduced unit emissions or does not exceed historic emissions, and, from that starting point, the units, as a group, reduce overall emissions to the level required for each state.   Conversely, EPA believes that a starting point allocating some units more than they have ever emitted would be illogical in programs aimed at reducing overall emissions.
      EPA believes that this selected allocation methodology for the final Transport Rule FIPs is within its authority under the Clean Air Act.  Section 110(a)(2)(D)(i)(I) of the CAA requires that emissions "within a state" that significantly contribute to nonattainment or interfere with maintenance in another state be prohibited.  In the final Transport Rule, EPA analyzed each individual state's significant contribution and interference with maintenance and calculated budgets that represent each state's emissions after the elimination of prohibited emissions.  The methodology used to allocate allowances in a state budget to individual units in the state has no impact on that state's budget or on the requirement that the state's emissions not exceed that budget plus variability.  Regardless of the allocation methodology used, the state's responsibility for eliminating its significant contribution and interference with maintenance remains unchanged.  This is reflected by the fact that allocations under each state's budget, regardless of how they are made, cannot change that state's budget.  In sum, the allocation methodology has no impact on the final rule's ability to satisfy the statutory mandate of CAA section 110(a)(2)(D)(i)(I) to eliminate significant contribution to nonattainment and interference with maintenance.
            Consistent with its broad authority in CAA sections 110(a)(2)(D)(i)(II) and 302(y), EPA believes that data quality, fuel-neutrality, control-neutrality, transparency, clarity, consistency with program goals, and successful experience in previous trading programs are reasonable factors on which to base the selection of an allowance allocation methodology for existing units for the final Transport Rule.  EPA believes that the transparency and clarity of this allocation approach builds credibility with the public that the government is distributing a public resource  -  i.e., allowances -- precisely as stated in this rulemaking, with clear execution that can be relatively easily verified.
            EPA also believes that the final Transport Rule's heat input-based approach for existing units is consistent with the goals of the Clean Air Act because it allocates allowances to existing units on the basis of a neutral factor that does not advantage or disadvantage a unit based on what fuel the unit burns or whether or not a unit has installed controls in anticipation of these regulations.  In contrast, allocations under the proposal's emissions-based methodology would give a greater share of allowances to units with higher emission rates, which are generally responsible for a greater share of a state's total emissions.  Because these higher-emitting rate units are generally responsible for a greater share of emissions, it follows that they are also responsible for a greater share of a state's significant contribution to nonattainment and interference with maintenance.  The proposal's emissions-based allocation methodology would disadvantage one of two otherwise identical existing units if it invested in emission reductions in anticipation of the Clean Air Interstate Rule or this final Transport Rule.
      The heat-input allocation methodology selected for the final Transport Rule does not have this flaw.  In contrast to the proposal's emissions-based allocation approach, the heat input allocation methodology selected by EPA yields a smaller proportion of allowances relative to emissions to higher-emission-rate units and a higher proportion of allowances relative to emissions to lower-emission-rate units.  For example, assume that in a state with two units and in a baseline year, Unit A combusts 100 MMBtu of heat input and emits 1000 tons while Unit B combusts 100 MMBtu of heat input and emits only 500 tons.  Assume also that this state's future Transport Rule emissions budget for this pollutant is only 500 tons.  Because Units A and B each make up an even share of historic heat input for the state, the final rule's heat input-based approach would allocate the same share of allowances (250 tons) to each unit.  In this example, Unit A's initial allocation of 250 is a smaller proportion of its historic emissions (25 percent of its baseline 1000-ton emissions), while Unit B's initial allocation of 250 is a larger proportion of its historic emissions (50 percent of its baseline 500-ton emissions).  Therefore, Unit B's ability to emit fewer tons per MMBtu of heat content used for generating electricity (as compared to Unit A) results in Unit B receiving a larger proportion of its historic emissions as an initial allocation share than Unit A receives.
      This relative distributional pattern yielded is consistent with the goals of CAA section 110(a)(2)(D)(i)(I) because under this distribution, higher-emitting units, which are responsible for a greater share of the state's significant contribution to nonattainment and interference with maintenance, would require relatively more allowances in order to cover their pre-existing emissions than would lower-emitting units.  EPA believes this initial allocation pattern is an appropriate reflection of the goals of CAA section 110(a)(2)(D)(i)(I).
      The heat input-based allowance methodology selected by EPA is fuel-neutral, control-neutral, transparent, based on reliable data, and similar to the allocation methodologies used in the NOX SIP Call and Acid Rain Program.  For all these reasons, EPA determined that it is appropriate to use a heat input-based allocation methodology in this rule.
      In addition, this allocation methodology is similar to an output-based allocation approach, which would base allocations on the quantity of electricity generated (rather than energy content combusted) and would also be fuel-neutral, control-neutral, and able to reward generation units that operate the most efficiently.  Many state and industry commenters advocated using an output-based approach due to its reported strong value in promoting efficiency.  However, at this time EPA does not have access to unit-level output data that is as quality-assured or comprehensive as its data sets on heat input across the units considered.  Therefore, EPA is using a heat input-based approach under the Transport Rule in part due to its ability to serve as a reasonable proxy for an output-based standard using the most quality-assured data that EPA has to date.
      In the NODA, EPA noted that final state budgets and allocations may differ from the proposed budgets and allocations because EPA was still in the process of updating its emissions inventories and modeling in response to public comments, including comments on the Integrated Planning Model.  Thus, unit-level allocations in the NODA provided an indication of the proportional share of a state's budget that would be allocated to individual existing units if the alternative methodologies were used.  The allocations made final today are based on budgets that reflect the updated modeling and comments received during the comment period.
c. Calculation of existing unit allocations under the final Transport Rule FIPs
   Allocations under this final methodology for each existing unit are determined by applying the following steps.
   1. For each unit in the list of potential existing Transport Rule units, annual heat input values for the baseline period of 2006 through 2010 are identified using data reported to EPA or, where EPA data is unavailable, using data reported to the Energy Information Administration (EIA).  For a baseline year for which a unit has no data on heat input (e.g., for a baseline year before the year when a unit started operating), the unit is assigned a zero value.  (Step 2 explains how such zero values are treated in the calculations.)  The allocation method uses a five-year baseline to approximate a unit's normal operating conditions over time.
   2. For each unit, the three highest, non-zero annual heat input values within the five-year baseline are selected and averaged.  Selecting the three highest, non-zero annual heat input values within the five-year baseline reduces the likelihood that any particular single year's operations (which might be negatively affected by outages or other unusual events) would determine a unit's allocation.  If a unit does not have three non-zero heat input values during the five-year baseline period, EPA averages only those years for which a unit does have non-zero heat input values.  For example, if a unit has only reported data for 2008 and 2009 among the baseline years and the reported heat input values are 2 and 4 MMBtus respectively, then the unit's average heat input used to determine its pro-rata share of the state budget is (2+4)/2 = 3.
   3. Each unit is assigned a baseline heat input value calculated as described in step 2, above, referred to as the "three-year average heat input."
   4. The three-year average heat inputs of all covered existing units in a state are summed to obtain that state's total "three-year average heat input."
   5. Each unit's three-year average heat input is divided by the state's total three-year average heat input to determine that unit's share of the state's total three-year average heat input.
   6. Each unit's share of the state's total three-year average heat input is multiplied by the existing-unit portion of the state budget (i.e., the state budget minus the state's new unit set-aside and, if applicable, minus the Indian country new unit set-aside) to determine that unit's initial allocation.
   7. An eight-year (2003-2010) historic emissions baseline is established for SO2, NOX, and ozone-season NOX based on data reported to EPA or, where EPA data is unavailable, based on EIA data.  This approach uses this eight-year historic emissions baseline in order to capture the unit-level emissions before and after the promulgation of CAIR.
   8. For each unit, the maximum annual historic SO2 and NOX emissions is identified within the eight-year baseline.  Similarly, the maximum ozone season NOX emissions from the eight-year baseline for each unit is identified.  These values are referred to as the "maximum historic baseline emissions" for each unit.
   9. If a unit has an initial historic heat-input based allocation (as determined in step 6) that exceeds its maximum historic baseline emissions (as determined in step 8), then its allocation equals the maximum historic baseline emissions for that unit.
   10. The difference (if positive) under step 9 between a unit's historic heat-input-based allocation and its "maximum historic baseline emissions" is reapportioned on the same basis as described in steps 1 through 6 to units whose historic heat-input-based allocation does not exceed its maximum historic baseline emissions.  Steps 7, 8, and 9 are repeated with each revised allocation distribution until the entire existing-unit portion of the state budget is allocated. The resulting allocation value is rounded to the nearest whole ton using conventional rounding.
   Table VI.D-1 below provides an illustrative application of the steps 1-10 in a hypothetical state.
Table VI.D-1:  Demonstration of Allocations Using Final Allocation Methodology
               in a Three-Unit State with an 80-Ton State Budget

                                   Steps 1-6
                                  Steps 7,8,9
                             Steps 1-9 Reiterated
                                    Step 10

                 Initial Historic Heat Input-based Allocation
                      Maximum Historic Baseline Emissions
                 Revised Historic Heat Input-based Allocation
                               Final Allocation
Unit A
                                      20
                                      16
                                      N/A
                                      16
Unit B
                                      30
                                      50
                                      32
                                      32
Unit C
                                      30
                                      50
                                      32
                                      32

2. Allocations to New Units
      EPA is finalizing -- similar to the proposal (75 FR 45310) -- an approach to allocate emission allowances to new units from new unit set-asides in each state.  A "new unit" may be any of the following:  (1) a covered unit commencing commercial operation on or after January 1, 2010;  (2) any unit that  becomes a covered unit by meeting applicability criteria subsequent to January 1, 2010;  (3) any unit that relocates into a different state covered by the Transport Rule; and any existing covered unit that stopped operating for two consecutive years but resumes commercial operation at some point thereafter.
      The proposed Transport Rule would have required that owners and operators initially request allowances from the new unit set-aside when the unit first became eligible for an allocation.  EPA now believes that it can identify which units become eligible and when they become eligible, based on information provided in other submissions (e.g., certificates of representation, monitoring system certifications, and quarterly emissions reports) that the final rule already requires such units to make to EPA.  EPA concludes that requiring owners and operators to submit requests of new unit set-aside allocations would impose an unnecessary burden on the owners and operators, as well as on EPA, and therefore EPA has removed this requirement in the final rule.
      The following sections describe the methodology in the final Transport Rule for allocating to new units, how EPA determined the size of new unit set-asides in the final rule, and how EPA has provided for allocations to new units that locate in Indian Country.
      a.  New Unit Allocation Methodology
      The proposal's new unit allocation methodology did not provide any allocation for a new unit's first control period of commercial operation.  Some commenters expressed concern about the lack of new unit allocations the first year of commercial operation. In order to address this concern, EPA is modifying the new unit allocation methodology in this final rule to include allocations to new units for the first control period in which the units are in commercial operation, as well as for control periods in subsequent years.
      The final rule's allocation to new units is performed in two "rounds."  The first round is the same as the new unit allocation procedures in the proposal (except for elimination of the requirements that owners and operators request the allocations) and occurs during the control period for which the allocations are made.  These first round allocations are based on new unit emissions during the prior control period and are recorded in allowance accounts in the Allowance Management System for the units by August 1 of each control period.  For example, for the 2012 vintage year, "first-round" allocations would be made to new units by August 1, 2012 based on their emissions in the 2011 control period (as monitored and reported in accordance with Part 75 of the Acid Rain Program regulations).  If the new unit set-aside is insufficient to accommodate first round allocations reflecting all new unit's prior control period emissions, the first round allocations are made pro rata to new units based on their share of total new unit emissions in the prior control period.
      The second round of allocations accommodates new units that come online during the control period for which the allocations are made and did not therefore receive any allocation in the first round.  The second round also accommodates new units that come online partway into the prior control period and therefore received an allocation in the first round that did not extend to cover operations in a full control period.  This second round of new unit allocation is therefore applicable only to new units coming online either during the control period of the allocations or during the control period immediately prior.  New units coming online earlier than the previous control period only receive first-round allocations from the new unit set-asides, as first-round allocations to those units is based on operational data spanning an entire control period.
      Second-round allocations are based on new unit emissions during the same control period as the vintage year of the allowances allocated.  For example, for the 2012 vintage year, "second-round" allocations are based on the difference between the new unit's emissions in the 2012 control period and the new unit allocation (if any) that the unit received in the first round of allocations.  For a unit coming online in 2012, this amount equals its total emissions during the 2012 control period.  For a unit coming online in 2011, this amount equals its incremental emissions in 2012 beyond its emissions in 2011, as such a unit would have already received a first-round allocation from the new unit set-aside based on its emissions in 2011.  Second-round allocations are recorded in allowance accounts by November 15 for the NOX ozone season trading program (ahead of the December 1 compliance deadline) and by February 15 of the following calendar year for NOX and SO2 annual trading programs (ahead of the March 1 compliance deadline).
      This methodology only allocates in the second round whatever allowances remain in the new unit set-asides after the first-round allocations have been recorded.  If the new unit set-aside available for second round allocations is insufficient to accommodate allocations based on the difference between control period emissions and any first round allocations for the units involved, then the second round allocations are made pro rate to the new units based on their share of the total of such differences.
      b. Determination of New Unit Set-Asides
      The proposed Transport Rule identified new units using a threshold online date of January 1, 2012, whereas the final Transport Rule uses a threshold online date of January 1, 2010.  As explained above, EPA adjusted this cutoff date because the final Transport Rule's allocation methodology for existing units requires that EPA possess at least one full year of historic data in order to calculate allocations.  As a consequence, EPA recognizes that the proposal's methodology to determine the size of the new unit set-asides based only on new EGUs forecast by the model would fail to account for known EGUs that have come online, or are planned to come online, after January 1, 2010.  Therefore, EPA has modified its approach to determining the size of the new unit set-asides in the final rule to account for both   "potential" units (i.,e., those that are not yet planned or under construction but are projected by modeling to be built) and "planned" units (i.e., those that are known units with planned online dates after January 1, 2010).  EPA uses the distinction between "potential" and "planned" new units to determine the ultimate size of each state's new unit set-aside (as a percentage of that state's budgets for each pollutant covered); however, the new unit allocation methodology described above applies the same to "potential" and "planned" new units.
      The first step of EPA's analysis to determine the new unit set-asides accounts for likely future emissions from potential units, and its methodology is taken directly from the Transport Rule proposal but reflects updated modeling (see "Allowance Allocation to Existing and New Units under the Transport Rule Federal Implementation Plans" TSD for detailed findings).  This analysis informed EPA's decision to establish a minimum new unit set-aside size of 2% of each state's budget for each pollutant that is configured to accommodate future emissions from potential units.
      For the final rule, EPA augmented its new unit set-aside determination to account for "planned" units through an additional step.  Because the location of these "planned" units is known and identified in EPA modeling, this second step is a state-specific modification of the size of the new unit set-asides.  That is, EPA only increased new unit set-asides above the 2% minimum established in the first step for states that had additional known units coming online between January 1, 2010 and January 1, 2012.
      The increases made to the new unit set-asides for these planned units reflect the projected emissions from these units.  Therefore, if the expected emissions of a given pollutant from all "planned" new units when in a given state were equal to 3% of that state's budget for that pollutant, then EPA added that amount to the base 2% new unit set-aside (creating a hypothetical new unit set-aside of 5% for that pollutant in that state).  See "Allowance Allocation to Existing and New Units under the Transport Rule Federal Implementation Plans" TSD for detailed results showing how EPA determined the size of each new unit set-aside reflecting the application of both of the steps described above.This approach to determining the size of state new unit set-asides is a logical outgrowth of the proposal, the NODA on allowance allocations, and updated modeling results. In fact, EPA received comments that using a January 1, 2010 cutoff date for distinguishing between existing and new units  would result in the new unit set-aside, as proposed, being insufficient to meet the needs of units already under construction.  EPA believes that the approach adopted in the final rule results in new unit set-asides that reasonably accommodate the foreseeable emissions from both planned and potential new units in each state.
The new unit allocation percentages for each state are shown in Table VII.D.2-1.

Table VII.D.2-1:  Percentage of State Emissions Budgets for Allowances in State New Unit Set-Asides

                                  Annual SO2
                                  Annual NOX
                               Ozone-Season NOX
                                    Alabama
                                      2%
                                      2%
                                      2%
                                   Arkansas
                                      ---
                                      ---
                                      2%
                                    Florida
                                      ---
                                      ---
                                      2%
                                    Georgia
                                      2%
                                      2%
                                      2%
                                   Illinois
                                      5%
                                      8%
                                      8%
                                    Indiana
                                      3%
                                      3%
                                      3%
                                     Iowa
                                      2%
                                      2%
                                      ---
                                    Kansas
                                      2%
                                      2%
                                      ---
                                   Kentucky
                                      6%
                                      4%
                                      4%
                                   Louisiana
                                      ---
                                      ---
                                      3%
                                   Maryland
                                      2%
                                      2%
                                      2%
                                   Michigan
                                      2%
                                      2%
                                      ---
                                   Minnesota
                                      2%
                                      2%
                                      ---
                                  Mississippi
                                      ---
                                      ---
                                      2%
                                   Missouri
                                      2%
                                      3%
                                      ---
                                   Nebraska
                                      4%
                                      7%
                                      ---
                                  New Jersey
                                      2%
                                      2%
                                      2%
                                   New York
                                      2%
                                      3%
                                      3%
                                North Carolina
                                      8%
                                      6%
                                      6%
                                     Ohio
                                      2%
                                      2%
                                      2%
                                 Pennsylvania
                                      2%
                                      2%
                                      2%
                                South Carolina
                                      2%
                                      2%
                                      2%
                                   Tennessee
                                      2%
                                      2%
                                      2%
                                     Texas
                                      5%
                                      3%
                                      3%
                                   Virginia
                                      4%
                                      5%
                                      5%
                                 West Virginia
                                      7%
                                      5%
                                      5%
                                   Wisconsin
                                      5%
                                      6%
                                      ---

      c. Procedures for Allocating New Unit Set-asides
      For the first round of new unit set-aside allocations, the Administrator will promulgate a notice of data availability informing the public of the specific new unit allocations and provide an opportunity for submission of objections on the grounds that the allocations are not consistent with the requirements of the relevant final rule provisions.  A second notice of data availability will subsequently be promulgated in order to make any necessary corrections in the specific new unit allocations.  As discussed elsewhere in this preamble, the final rule establishes a different schedule for promulgation of these notices of data availability than the proposed rule.  In particular, a single set of deadlines (i.e., for the first notice in the first round of allocations, June 1 of the year for which the new unit allocations are described in the notice and, for the second notice of the first round, August 1 of that year) for promulgation of the notices is established for all of the Transport Rule trading programs.  EPA believes that these deadlines will provide sufficient time for EPA to obtain final emissions data for the prior year for the units involved and to calculate the allocations and promulgate the notices.  Further, the approach of using the same deadline for all of the Transport Rule trading programs will simplify EPA's implementation and reduce the complexity of the process for source owners and operators.
      For the second round of new unit set-aside allocations, the Administrator will also promulgate two notices of data availability.  However, the deadlines for the notices differ for the NOX ozone season trading program and for the SO2 and NOX annual trading programs because control period emissions data (used in making second round allocations) become available sooner, and the compliance deadline for holding allowances covering emissions is sooner, in the NOX ozone season trading program.  The control period in the NOX ozone season program ends on September 30, and fourth quarter emissions reports must be submitted to EPA by October 30, while the control periods in the SO2 and NOX annual programs end on December 31 and fourth quarter emission reports are due by January 30.  Further, in order for the second round allocations to be available to be used for compliance with the allowance-holding requirement, the second round needs to be completed before the compliance dates, which are December 1 in the NOX ozone season program and March 1 in the SO2 and NOX annual programs.  Consequently, for the NOX ozone season program the Administrator will promulgate by September 15 a notice of data availability identifying the units eligible for second round allocations and by November 15 a second notice of data availability of the list of eligible units and their second round allocations, which will also be recorded in the allowance accounts by that date.  The comparable deadlines for the SO2 and NOX annual programs are December 15 and February 15.  EPA believes that these deadlines will provide sufficient time for EPA to identify the units and obtain their needed emissions data and to calculate the allocations and promulgate the notices.
      d. Addition of Allowances to New Unit Set-asides
      As discussed elsewhere in this preamble, EPA proposed that, if a unit with an existing-unit allocation does not operate for three consecutive years, the allowances that would otherwise have been allocated to that unit, starting in the seventh year after the first year of non-operation, would be allocated to the new unit set-aside for the state in which the retired unit is located.  EPA is retaining this provision in the final rule but is changing the time of non-operation to two years and the time of allowance allocation to a non-operating unit to four years.  Starting in the fifth year of non-operation, allowances will be allocated to the new unit set-aside for the state in which the non-operating unit is located.
      EPA received comments that the new unit set-asides were not sufficient to encourage the operation of new units.  One commenter suggested that allowance allocations should cease after three years of non-operation because the financial incentive gained from receiving allowances beyond the 3-year period is insignificant relative to operating and fuel costs.  Another commenter said that providing allowances to non-operating units is unnecessary and distorts the market.
      In addition to increasing the size of the new unit set-aside in this final rule, as described above, EPA is terminating existing unit allocations starting in the fifth year after the unit does not operate for two consecutive years and reallocating to the new unit set-aside the allowances that the unit otherwise would have received for the fifth and subsequent years in order to make them available for new units in the state.  This approach allows the new unit set-asides to grow over time.
      e. Allocations to New Units Locating in Indian Country
      EPA received several comments on the proposed rule that it did not explicitly address the distribution of allowances to potential new units built in Indian country.  EPA recognized this concern and requested comment on this topic in the January 7, 2011 NODA.
      In the final rule, EPA is providing a mechanism to make allowances available in the future for new units built in Indian country.  The final rule establishes an Indian country new unit set-aside for each pollutant in each state whose borders encompass Indian country (i.e., Florida, Iowa, Kansas, Louisiana, Michigan, Minnesota, Mississippi, Nebraska, New York, North Carolina, South Carolina, Texas, and Wisconsin).  EPA will retain administration of these Indian country new unit set-asides as part of the Transport Rule trading programs whether or not a Transport Rule state elects to modify or replace the Transport Rule FIPs through approved SIP revisions.  EPA does not create Indian country new unit set-asides for states lacking Indian country within their borders.
      EPA determined the size of each Indian country new unit set-aside by calculating the ratio of square mileage of Indian country to the square mileage of the  state within whose borders Indian country is located.  This calculation yielded a maximum percentage of 5 percent when assessing all of the states encompassing Indian country subject to the final Transport Rule; this is referred to as the "5 percent Indian country factor" below.  To determine the maximum percentage, EPA used the American Indian Reservations/Federally Recognized Tribal Entities dataset, which contains data for the 562 federally recognized tribal entities in the contiguous U.S. and Alaska.  EPA accessed the data to analyze the Transport Rule region and compare the square miles of Indian country with the square miles of the Transport Rule state that includes the Indian country.  EPA then took the highest percentage as the number to be applied across all states with Indian country to determine the size of the Indian countrynew unit set-aside pertinent to that state's budgets under the Transport Rule.  EPA chose to use the maximum percentage (5 percent) from the Indian country analysis to determine the Indian country set-aside for each state on the basis that this approach would reserve a reasonable number of allowances from each state's budget for potential allocation to new units that may locate in Indian country within that state's borders.  Any allowances from the Indian country new unit set-aside that are not allocated in a given control period are redistributed into the state's new unit set-aside.  As discussed above, any any allowances not allocated from that new unit set-aside are redistributed to existing units based on the existing units' share of the total existing unit allocations.
      To calculate the size of each tribal new unit set-aside, EPA applied this 5 percent Indian country factor to the portion of the state's new unit set-aside originally determined by accounting for "potential" new units, which as described above was set at 2% of each pollutant's budget in each state.  Therefore, the Indian country new unit set-aside is 5 percent of 2 percent of a state's budget, or 0.1 percent of that total state budget.  EPA did not apply the 5 percent Indian country factor to the state-specific planned unit portion of each state's new unit set-aside because the planned unit portion is determined using projected emissions from specific, known units coming online after January 1, 2010 and none of these known units are located in Indian country.
The Indian country new unit set-asides in the following Transport Rule states with Indian Country are shown in Table VII.D.2-2.

   Table VII.D.2-2:  New Unit Set-Aside Allowances for Indian Country (tons)

                                 SO2 2012-2013
                             SO2  2014 and Beyond
                               Annual NOX  2012
                               Annual NOX  2012
                            Ozone-Season NOX  2012
                            Ozone-Season NOX  2014
Florida
                                      ---
                                      ---
                                      ---
                                      ---
                                      28
                                      28
Iowa
                                      107
                                      75
                                      38
                                      37
                                      ---
                                      ---
Kansas
                                      42
                                      42
                                      31
                                      26
                                      ---
                                      ---
Louisiana
                                      ---
                                      ---
                                      ---
                                      ---
                                      13
                                      13
Michigan
                                      229
                                      144
                                      60
                                      58
                                      ---
                                      ---
Minnesota
                                      42
                                      42
                                      30
                                      30
                                      ---
                                      ---
Mississippi
                                      ---
                                      ---
                                      ---
                                      ---
                                      10
                                      10
Nebraska
                                      65
                                      65
                                      26
                                      26
                                      ---
                                      ---
New York
                                      27
                                      19
                                      18
                                      18
                                       8
                                       8
North Carolina
                                      137
                                      58
                                      51
                                      42
                                      22
                                      18
South Carolina
                                      89
                                      89
                                      32
                                      32
                                      14
                                      14
Texas
                                      244
                                      244
                                      134
                                      134
                                      63
                                      63
Wisconsin
                                      79
                                      40
                                      32
                                      30
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      Under the FIPs, EPA allocates allowances from Indian country new unit set-asides in essentially the same manner as it allocates allowances from state new unit set-asides.  The approach for identifying, and determining the number of allowances allocated to, new units in Indian country is the same as the approach for identifying and determining allocations for non-Indian country new units covered by the state new unit set-aside, and allocations are made in two rounds using the same schedules for promulgation of notices of data availability.  However, as discussed above, unallocated allowances in the Indian country set-asides are handled differently from unallocated allowances in the state new unit set-asides in that  unallocated Indian country new unit set-aside allowances are first transferred back into the state new unit set-aside and then, if still not allocated to new units, are distributed to existing units in the state.  EPA believes that the above-described approach in establishing and handling the Indian country new unit set-asides and state new unit set-asides is a reasonable way of making a sufficient amount of allowances available for new units in the state and Indian country located in the state and ensuring that the entire state budget is available to either new or existing units in the state and Indian country. EPA retains administration of these Indian country new unit set-asides (and, of course, the portions of state budgets that comprise these set-asides) as part of the Transport Rule trading programs even if a state elects to modify or replace the Transport Rule FIPs through approved SIP revisions.  EPA continues to manage and distribute the Indian country new unit set-aside allowances in  the same manner as under the FIPs .  Unallocated allowances in the Indian country new unit set-aside will be returned to the portion of the state budget allocated under the approved SIP's allocation provisions.    EPA believes that this approach is reasonable because EPA, rather than the states, has the authority and responsibility of administering the Transport Rule with regard to new units that locate in Indian country.

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