XVIII. F. 2 Document No.: OAR 2003 0053 2285 Commenter: Virginia Independent Power Producers Comment: In the December 2, 2005 notice announcing the reconsideration of the four CAIR issues, EPA noted that its analysis of the CAIR SO2 methodology considered the allocation of Title IV SO2 allowances to electric generating units not currently in the Acid Rain Program through the voluntary opt in provisions . The agency seems to assume that voluntary opt in would eliminate any undue hardship on IPPs and QFs that opt in to the Acid Rain Program by providing an allocation of a certain amount of SO2 opt in allowances. The voluntary opt in option is not a sufficient solution and would generally result in the allocation of a wholly inadequate number of allowances to IPPs and QFs for the following reason. [[ ( p. 5) ]] Under the EPA opt in regulations, the allocation of allowances would be based on the SO2 emissions of the units during the first three calendar years of their operation, and during this period many of the units were dispatched by the purchasing utilities on a reduced basis when compared to the more current dispatch levels. Under the fixed price formula PPAs, the IPPs and QFs are compensated by ( i) a fixed capacity price that is tied to minimum dispatch availability requirements and ( ii) a variable energy price that is linked to the amount of electricity that is actually dispatched and a pass through on the costs of fuel to generate that electricity. The Public Utilities Regulatory Policy Act of 1978 mandated that utilities enter into electricity offtake contracts with IPPs and QFs, but they did not mandate that the plants had to be dispatched at near full capacity levels. Utilities generally will dispatch their least cost generation facilities first, and the IPPs and QFs under contract to utilities were not necessarily the lowest cost units. If EPA does not grant an exemption for IPPs and QFs substantially similar to the statutory exemption under the Acid Rain Program, then it should at least modify the opt in rules to allow IPPs and QFs to select three years of operation that are more representative of the plant= s highest dispatch levels. Nevertheless, even if the CAIR affected IPPs and QFs did receive opt in SO2 allowance allocations based on emission rates that are more representative of full capacity operation, the units would still face significant SO2 allowance costs to meet CAIR reduction targets and such compliance costs would not be able to be passed through to the purchasing utilities. This is in marked contrast with the purchasing utility= s ability to seek a full recovery of any CAIR SO2 compliance costs incurred by its own generation units. [[ ( p. 5) ]]

Response:

The commenters claim that their costs to comply with the CAIR SO2 annual program are excessively high. The economics of an IPP are different depending upon whether the unit has a fixed price power purchase agreement in place or whether it is selling electricity on the wholesale market. Units that had power purchase agreements ( PPAs) with fixed prices in place on November 15, 1990, are exempt from title IV and do not receive title IV allowances. The commenters state that, while their agreements are in effect, these units are not able to pass through cost increases, such as the cost of compliance with CAIR, except where specific escalations are provided ( e. g., compensation for increases in fuel costs or inflation).

While under the agreements and exempt from title IV, the units can opt into the title IV program and receive allowances as opt in units. Commenters claim that the title IV opt in provisions could allocate allowances to them at levels below their projected emissions because the units may operate more in the future. The commenters add that it is not cost effective for the units to reduce SO2 emissions by installing advanced emission controls because the units already achieve significant reductions and have fixed price contracts that do not allow them to pass through control costs.

The second scenario is the period beginning when the units' power purchase agreements expire and the units lose their title IV exemption. As title IV affected units, they lose their title IV optin status and can no longer receive title IV allowances under the title IV opt in provisions. These units are no longer locked into their power purchase contracts and are free to participate in the wholesale electricity markets. The commenters contend that reducing emissions   even when they are free to pass through the cost of compliance   is not cost effective, because most IPPs already operate at lower SO2 emission rates than many other sources. This, however, belies the real issue, since under a trading program, sources have multiple compliance options including installing emission controls, switching fuels or purchasing allowances. If a source's control costs are above the marginal cost of control in the region, the unit is likely to comply by purchasing allowances, thereby reducing the cost of control to the market price.

EPA disagrees with the commenters' claim that complying with the CAIR would result in these units being economically unviable. The commenters provided only limited information to support their claim. When examined by EPA in greater detail, this commenter provided information shows that these units would, at a minimum, incur significantly lower compliance costs than they estimate and would generally continue to operate at a profit. The commenter has not substantiated their claim. Further, the commenter provided information suggests that the potential financial impacts to these units would vary from unit to unit and does not support providing an exemption for the entire source category. In addition, EPA analysis done in the absence of substantial information provided by the commenters ( i. e., the analysis of the typical cost of production for a CFB combusting waste coal) indicated that IPP would continue to operate and profit, in contradiction to the commenters' claims. EPA notes that the commenters expressed concern for the potential compliance costs of the CAIR SO2 program but not for the CAIR NOx annual and ozone season programs.

Below, EPA responds to the commenters' claims that CAIR will make them economically unviable by considering ( 1) the period of time in which their power purchase agreements are in effect and ( 2) the period of time after their contracts have expired. Additional discussion and supporting analysis is presented in the Technical Support Document for the Rule to Reduce Interstate Transport of Fine Particulate Matter and Ozone ( Clean Air Interstate Rule), Final Notice of Reconsideration: IPP in the CAIR and CAIR FIP ( IPP in the CAIR and CAIR FIP TSD).

IPPs with PPAs in Effect EPA disagrees with the commenters claim that complying with CAIR would result in these units being economically unviable for the period of time when their PPAs are in effect and they could receive allowances by opting into title IV. EPA believes that opting into title IV can significantly offset potential compliance costs. EPA analysis presented in the IPP in the CAIR and CAIR FIP TSD supports EPA's belief that IPP generally could receive enough SO2 allowances to account for their current emission levels by opting into title IV. The commenters' analysis of the potential impacts of CAIR compliance, and EPA's evaluation of this analysis, is discussed below.

EPA evaluated the limited analysis submitted by the commenters to support their claim that CAIR would make them economically unviable during the period of time when the units have PPAs in effect. More specifically, EPA evaluated the commenters' analysis of the ratio of their estimated cost of compliance with CAIR to their projected revenue. As shown in the IPP in the CAIR and CAIR FIP TSD, the commenter overestimated the ratio for their units by an average of 493 percent and 297 percent in 2010 and 2015, respectively. EPA based its recalculation of the estimated cost of compliance under CAIR on the unit level emissions reported by the commenter and the proper value for the projected cost of emitting one ton of SO2 under CAIR in 2010 and 2015 ($ 616/ ton and $ 892/ ton respectively). 1 These recalculated ratios range from under 1% to 4%.

The commenter also neglected to provide information on a particular cut off ratio that defines a point at which the units would become economically unviable. EPA also notes that consideration of cost to revenue ratios in the RIA is not used as a determination of economic viability, but rather as a conservative screening measure to identify groups of units for which the Agency should evaluate the potential financial impacts. A finding that a unit or group of units might have a cost to revenue ratio of greater than 3% does not preclude the Agency from regulating them, but is used as an means of identifying types of units that could be have significant financial impacts.

EPA believes that analysis presented in today's rulemaking ( preamble, response to comment document, and IPP in the CAIR and CAIR FIP TSD) demonstrates that these units would continue to operate and could be profitable under CAIR. The commenters have not shown that 1 The $ 616/ ton and $ 892/ ton cost of emitting one ton of SO2 are projections from EPA modeling that includes the impacts of the other programs, such as the Clean Air Mercury Rule and Clean Air Visibility Rule. the cost to revenue ratios, especially when recalculated to appropriately account for costs, would result in their units being, as they claim, " economically unviable."

In addition to the evaluation of the cost to revenue ratios, EPA further investigated the potential impacts of CAIR on IPP while their PPAs remain in effect by examining how their contract prices might compare with their potential costs to operate. An EPA search of publicly available information produced a contract for a Pennsylvania IPP that commenced operation in 1993.2 The contract indicates that the PPA agreement compensates the IPP at $ 62.72 per MWh in 1999.3 In other words, this IPP, while being bound by a fixed price contract, was being compensated at levels well above their EPA estimated likely cost of operation ( discussed below and in the IPP in the CAIR and CAIR FIP TSD) and EPA projected wholesale electricity prices in 2010 and 2015. Additional, limited information submitted by commenters also suggest that at least some IPP, while constrained by their PPAs, are compensated at levels well above market rates   rates that would allow them to absorb compliance costs. Specifically, the commenter states that one facility " happens to have a PPA that includes very attractive current energy prices." The commenter continues that when the PPA expires, " revenue is estimated to drop  with the switch to market prices." In other words, when this unit must compete on the market, its income will drop. This supports EPA's belief that at least some IPP are well compensated by their PPAs and the cost of complying with CAIR would not make them economically unviable.

IPP After PPAs Expire Because the unit specific information and analysis provided by the commenters was limited, EPA conducted an analysis using generally available information to evaluate the potential impact of the cost of complying with CAIR for a typical CFB combusting waste coal. While this analysis was conducted to evaluate the potential financial impacts of complying with CAIR on units combusting waste coal, EPA believes it is applicable to IPPs in general. EPA notes that there may be some slightly differences in the price of fuel but the costs assumed in the EPA analysis should reasonably similar to those of a typical IPP burning coal.

This analysis specifically applies to periods of time when the power purchase agreements have expired ( i. e., the units have lost the exemption from title IV and can not receive title IV opt in allowances) and the units are free to participate in the electricity markets. This analysis examined how the potential cost to operate a typical waste coal fired CFB unit ( including the cost of complying with CAIR) compares to the potential price it would receive on the electricity market. As shown in table VI. A 1, the estimated cost of producing electricity for a typical waste coal fired CFB would be significantly less than the EPA projected wholesale price and the forecasted price of electricity. In other words, the typical facility would produce electricity, even with the cost of complying with CAIR, at a cost that below what the market would be willing to pay. In general, waste coal fired facilities will continue to be profitable, even when factoring in the cost of complying with CAIR.

Table VI. A 1: Costs of Operating a Typical CFB Plant Burning Waste Coal Components of Operating Costs Cost to Operate Cost to Operate 2 Environmental Power Corporation Form 10 K filing is located in the docket. 3 Price is escalated to 1999 for comparison purposes. 2010 ($/ MWh) 2015 ($/ MWh) Variable O& M $ 2.11 $ 2.11 Fixed O& M $ 5.31 $ 5.31 Fuel Cost $ 7.28 $ 7.20 SO2 Allowance Cost $ 1.53 $ 2.17 NOx Allowance Cost $ 0.77 $ 0.95 Total Operating Cost* $ 17.00 $ 17.74 Base Case Wholesale Electricity Price** $ 25.43 $ 33.46 CAIR Wholesale Electricity Price** $ 27.10 $ 36.06 * The total operating cost estimate, as well as component costs, are described in the TSD IPP in the CAIR and CAIR FIP. ** IPM projected wholesale electricity prices in the under the Base Case and CAIR ( EPA 2006).

Other Considerations While EPA evaluated the commenters' claims by analyzing the potential financial impacts of complying with the CAIR SO2 annual program only and found no basis on record for the commenters claims of being economically unviable, EPA believes that there are other consideration that can influence the economic viability ( i. e., whether they will cease to operate) of the plants. First, the CAIR includes two NOx control programs   one annual and one summertime   that each provide CAIR allowance budgets that States can allocate to any units they wish. ( EPA notes that these units have not expressed concern over the cost of compliance with either of the CAIR NOx programs.) In addition, coal fired units ( including units fired with waste coal) can receive mercury allowances under the Clean Air Mercury Rule ( CAMR). Allowances from all three programs ( the CAIR NOx annual program, the CAIR NOx ozone season program, and the CAMR) are valuable commodities and can provide mechanisms for States wishing to encourage certain types of generation to do so. Finally, there are environmental programs, outside of the CAIR and CAMR programs, that also provide benefit to these IPP and could be considered in the overall viability of the plants. One example is the potential benefits of IPP generating renewable energy credits ( RECs) as part of statewide renewable portfolio standards ( RPSs). In Pennsylvania, where some of the commenters' units are located, an IPP can generate valuable RECs. When taken as a whole, these other factors in a IPP environmental compliance costs could provide significant benefit to these units.

In summary, EPA does not agree with commenters that believe that complying with the CAIR FIP or CAIR SO2 annual program or would result in this category of units being economically unviable. EPA rationale for this is described in the CAIR FIP NFR preamble, this response, and the IPP in the CAIR and CAIR FIP TSD. This response provides additional discussion of the EPA evaluation of the commenters' analysis of the unit specific cost to revenue ratios as well as the EPA's analysis of estimated cost of typical waste coal fired CFB. The evaluation of the commenters' analysis, provided to support their claim of economic burden for periods of time when the IPP have PPAs in effect, indicated that they had significantly overestimated the cost of complying with CAIR and, as a result, did substantiate their claim. In addition, EPA's analysis of a typical unit showed that, when the units' PPA have expired, the units would likely operate and continue to make a profit once they were free to enter the electricity markets. For these reasons, EPA has not included an exemption for IPP or IPPs in the CAIR FIP or CAIR trading programs.

XVIII. F. 3 Document No.: OAR 2003 0053 2282.1 Commenter: South Carolina Public Service Authority and JEA Comment: The Notice of Reconsideration explains that EPA is assuming that, under an Acid Rain Programbased SO2 trading system, companies owning non Acid Rain units subject to CAIR would opt into the Acid Rain Program in order to receive allowances to cover their units= emissions under CAIR. EPA further assumes that companies that own both non CAIR and CAIR units would transfer Acid Rain Program allowances from the former to the latter. EPAs data for 2010 show surrender of 25,000 allowances from title IV opt in units and 131,000 allowances acquired by companies from their non CAIR EGUs. These actions would not be possible under alternative allocation methods that do not make use of title IV allowances. [[ Docket number 2282.1, p. 16]][[ See docket number 2282.1, pp. 16 17 for further discussion of this issue.]]

Response: See Notice of Final Action on Reconsideration, Section III. A, " Potential for Regional Emissions Increases." It should be noted that EPA estimates that if the Agency were to not use the title IV approach, there would be approximately 260,000 title IV allowances, representing that many tons of SO2 emissions, that sources in non CAIR States would have incentive to use to cover emissions at little to no cost ( an increase equal to about 30 percent of the 0.9 million tons of emissions EPA projects for non CAIR region). This increase would occur because title IV allowances would have no economic value.

XVIII. F. 4 Document No.: OAR 2003 0053 2301 Commenter: Pennsylvania Department of Environmental Protection ( PADEP) Comment: EPA= s CAIR affects units that are exempt from the Acid Rain Program and, therefore, were not issued SO2 allowances. Requiring these units to hold SO2 allowances under CAIR will cause the owners or operators severe and irreversible financial damage owing to the fact that these units produce power and steam under long term, fixed price contracts that cannot be adjusted to compensate for the costs of complying with the CAIR. [[ ( p. 1) ]] EPA assumed that these units might be able to opt in, but this is incorrect for these units. EPA also chose to exempt Municipal Waste Combustors ( MWC) that meet the criteria as affected units based on the fact that a proper cost effectiveness analysis was not conducted. Similarly, EPA has failed to properly evaluate cost effectiveness of cogeneration units and waste coal combustors that cannot control emissions any more cost effectively than the MWCs. Either MWCs should be affected or waste coal combustors should also be exempted. [[ ( pp. 1 2) ]] EPA= s position is unsustainable. It is highly inequitable to issue allowances to one set of generators and require a 50% reduction, while as a result of having issued them no allowances effectively impose a 100% reduction on the waste coal combustors and cogeneration units. EPA= s contention that these facilities have subsidiary relationships from which to draw allowances is incorrect. The underlying justification for the control strategy is that it presumes the trading program distributes compliance costs among units and does not create inequitable and energy market competitive distortions in this case unallocated units are forced to bear highly disproportionate compliance costs, thereby providing a significant competitive advantage to allocated units. [[ ( p. 2) ]] In addition, the SO2 emissions from these units were not included in the original Acid Rain Program. Therefore, their emissions are in excess of the budget set by the Acid Rain Program. Congress effectively authorized the emissions by not including these units in the Acid Rain Program. EPA can, therefore, either add these emissions to the CAIR SO2 budget and issue the units allowances, or exempt the units from CAIR. In either case, EPA could increase the retirement ratio from existing Acid Rain units to achieve the level of reductions needed by the CAIR. The small adjustment would not upset the cost effectiveness of CAIR compliance for existing Acid Rain units, while it would alleviate the severe financial harm the CAIR imposes on non Acid Rain units. [[ ( p. 2) ]] Waste coal burners and cogeneration units that were not included in the Acid Rain Program did not fall under the original Acid Rain cap. By bringing them into the CAIR program without issuing them SO2 allowances, EPA has imposed upon them standards and requirements not placed on any other existing facility under CAIR. The units are relatively clean and provide a useful environmental benefit to Pennsylvania by cleaning up old waste coal piles. The Commonwealth strongly urges EPA to exempt these units from CAIR requirements or allocate SO2 allowances under CAIR. [[ ( p. 3) ]]

Response:

See response to comment XVIII. A. 1 and XVIII. E. 4, as well as the CAIR FIP/ 126 Response to Comments, Section VI. A.

Also, EPA further investigated the potential impacts of CAIR on waste coal fired units while their PPAs remain in effect by examining how their contract prices might compare with their potential costs to operate. An EPA search of publicly available information produced a contract for a Pennsylvania waste coal fired facility that commenced operation in 1993. Environmental Power Corporation Form 10 K filing is located in the docket. The contract indicates that the PPA agreement compensates the waste coal fired facility at $ 62.72 per MWh in 1999. Price is escalated to 1999 for comparison purposes. In other words, this waste coal fired facility, while being bound by a fixed price contract, was being compensated at levels will above their EPA estimated likely cost of operation ( discussed below and in the Waste Coal Fired Units in the CAIR and CAIR FIP TSD) and EPA projected wholesale electricity prices in 2010 and 2015. Additional, limited information submitted by commenters also suggest that at least some waste coal fired units, while constrained by their PPAs, are compensated at levels well above market rates   rates that would allow them to absorb compliance costs. Specifically, the commenter states that one facility " happens to have a PPA that includes very attractive current energy prices." The commenter continues that when the PPA expires, " revenue is estimated to drop  with the switch to market prices." In other words, when this unit must compete on the market, its income will drop. This supports EPA's belief that at least some waste coal fired units are well compensated by their PPAs and the cost of complying with CAIR would not make them economically unviable. Document No.: OAR 2003 0053 2288.1 Commenter: GE Energy Financial Services Comment: In the December 2, 2005 notice announcing the reconsideration of the four CAIR issues, EPA noted that its analysis of the CAIR SO2 methodology considered the allocation of Title IV SO2 allowances to electric generating units not currently in the Acid Rain Program through the voluntary opt in provisions. The agency seems to assume that voluntary opt in would eliminate any undue hardship on IPPs and QFs that opt in to the Acid Rain Program by providing an allocation of a certain amount of SO2 opt in allowances. The voluntary opt in option is not a sufficient solution and would generally result in the allocation of a wholly inadequate number of allowances to IPPs and QFs for the following reason. [[ ( 2288.1, p. 4) ]] Under the EPA opt in regulations, the allocation of allowances would be based on the SO2 emissions of the units during the first three calendar years of their operation, and during this period many of the units were dispatched by the purchasing utilities on a reduced basis when compared to the more current dispatch levels. Under the fixed price formula PPAs, the IPPs and QFs are compensated by ( i) a fixed capacity price that is tied to minimum dispatch availability requirements and ( ii) a variable energy price that is linked to the amount of electricity that is actually dispatched and a pass through on the costs of fuel to generate that electricity. The Public Utilities Regulatory Policy Act of 1978 mandated that utilities enter into electricity offtake contracts with IPPs and QFs, but they did not mandate that the plants had to be dispatched at near full capacity levels. Utilities generally will dispatch their least cost generation facilities first, and the IPPs and QFs under contract to utilities were not necessarily the lowest cost units. If EPA does not grant an exemption for IPPs and QFs substantially similar to the statutory exemption under the Acid Rain Program, then it should at least modify the apt in rules to allow IPPs and QFs to select three years of operation that are more representative of the plant= s highest dispatch levels. Of course, even if the CAIR affected IPPs and QFs did receive opt in SO2 allowance allocations based on emission rates that are more representative of full capacity operation, the units would still face significant SO2 allowance costs to meet CAIR reduction targets and such compliance costs would not be able to be passed through to the purchasing utilities. This is in marked contrast with the purchasing utility= s ability to seek a full recovery of any CAIR SO2 compliance costs incurred by its own generation units." [[ ( 2288.1, p. 5) ]]

Response: See response to comment XVIII. F. 2.

XVIII. F. 6 Document No.: OAR 2003 0053 2269.1 Commenter: AES Corporation Comment: At 70 Fed. Reg. 72273 of the Notice of Reconsideration, EPA states > This analysis assumed that companies owning non Acid Rain units affected by CAIR would opt into the Acid Rain Program because they would receive title TV allowances to cover a portion of the unit= s emissions under CAIR= [[ Docket number 2269.1, p. 3]] While this option may appear to be a solution to the problem created by EPA= s failure to recognize and honor the Congressional determination to exempt these facilities from the SO2 cap and trading program, it would provide significantly fewer allowances than these units would need to operate. Two examples illustrate the inadequacy of this option: [[ Docket number 2269.1, p. 3]] i. A unit that commenced operation after January 1, 1985 ( e. g., Warrior Run) would have its Title IV opt in allocation calculated based on heat input, sulfur content and fuel consumption for its first three years of operation, and its actual emission rate ( which should be lower than its allowable emission rate). Therefore, it would get an allocation roughly equivalent to its current emissions. With this allocation it would be granted only 50% and 35% of the allowances needed for compliance in Phase 1 and 2 of CAIR, respectively, due to the rule= s 2: l and 2.86: l surrender ratios. [[ Docket number 2269.1, p. 3]] ii. For units that commenced operating prior to January 1, 1985, the data used to determine baseline conditions are 1985, 1986 and 1987. This is the situation for Beaver Valley. However, not only does the allowance shortfall outlined above exist, but the plant= s utilization rate during those years is not representative of subsequent year, or current operations. Therefore, Beaver Valley= s allocation under the opt in scenario would be significantly lower than the 50% and 35% of actual SO2 emissions allocation outlined above. The Acid Rain opt in regulations do not allow for alternative baseline years to be used to rectify this type of situation. [[ Docket number 2269.1, p. 3]] These units are well controlled, with low SO2 emission rates. While the Title IV opt in provision would provide some allowances, the actual number would be very small compared to the plants= need. This would result in the inequitable situation where well controlled, low emitting units with contract prices that were set before passage of the CAA Amendments of 1990 ( therefore, having no opportunity of cost passthrough) would need to buy allowances, when comparable or even higher emitting units ( most with the ability to passthough new compliance costs) may even have excess allowances to sell. It is hard to see where this was the intent of CAIR. [[ Docket number 2269.1, pp. 3 4]] Accordingly, AES believes that CAIR needs to be revised to continue the Title IV SO2 exemption that Congress enacted for IPPs under long term contracts that was in place previously for both the legal and equity reasons identified above. [[ Docket number 2269.1, p. 4]]

Response: See responses to comment XVIII. A. 1 and XVIII. F. 2, FIP/ 126 final rule, Section VI. E., and FIP/ 126 response to comments, Section VI. A.

XVIII. F. 7 Document No.: OAR 2003 0053 2287.1 Commenter: Birchwood Power Partners, L. P. Comment: In the December 2,2005 notice announcing the reconsideration of the four CAIR issues, EPA noted that its analysis of the CAIR SO2 methodology considered the allocation of Title IV SO2 allowances to electric generating units not currently in the Acid Rain Program through the voluntary opt in provisions. The agency seems to assume that voluntary opt in would eliminate any undue hardship on IPPs and QFs that opt in to the Acid Rain Program by providing an allocation of a certain amount of SO2 opt in allowances. The voluntary opt in option is not a sufficient solution and would generally result in the allocation of a wholly inadequate number of allowances to IPPs and QFs for the following reason. [[ ( 2287.1, p. 5) ]] Under the EPA opt in regulations, the allocation of allowances would be based on the SO2 emissions of the units during the first three calendar years of their operation, and during this period many of the units were dispatched by the purchasing utilities on a reduced basis when compared to the more current dispatch levels.* Under the fixed price formula PPAs, the IPPs and QFs are compensated by ( i) a fixed capacity price that is tied to minimum dispatch availability requirements and ( ii) a variable energy price that is linked to the amount of electricity that is actually dispatched and a pass through on the costs of fuel to generate that electricity. The Public Utilities Regulatory Policy Act of 1978 mandated that utilities enter into electricity offtake contracts with IPPs and QFs, but they did not mandate that the plants had to be dispatched at near full capacity levels. Utilities generally will dispatch their least cost generation facilities first, and the IPPs and QFs under contract to utilities were not necessarily the lowest cost units. During the first three calendar years of operation, the Birchwood Power facility was dispatched at capacity rates that were not nearly as high as dispatch rates in more recent years, and the plant would be disadvantaged by using its early years of operation as an opt in baseline. [[ ( 2287.1, p. 5) ]] If EPA does not grant an exemption for IPPs and QFs substantially similar to the statutory exemption under the Acid Rain Program, then it should at least modify the option rules to allow IPPs and QFs to select three years of operation that are more representative of the plant= s highest dispatch levels. Nevertheless, even if the CAIR affected IPPs and QFs did receive out in SO2 allowance allocations based on emission rates that are more representative of full capacity operation, the units would still face significant SO2 allowance costs to meet CAIR reduction targets and such compliance costs would not be able to be passed through to the purchasing utilities. This is in marked contrast with the purchasing utility= s ability to seek a full recovery of any CAIR SO2 compliance costs incurred by its own generation units. [[ ( 2287.1, p. 5) ]]

Response: See response to comment XVIII. F. 2.

XVIII. G. Comments on late notice of data corrections documents [ There are no comments in this section.]

XVIII. H. General XVIII. H. 1 Document No.: OAR 2003 0053 2268.1 Commenter: Northeast States for Coordinated Air Use Management ( NESCAUM) Comment: Sulfur dioxide ( SO2) allocation methodology in the Clean Air Interstate Rule ( CAIR) model trading rules: EPA has asked for comment on analyses conducted of its SO2 allocation methodology. EPA has relied on the use of Title IV ( Acid Rain Program) SO2 allowances for the CAIR model trading program. As stated in previous comments, we do not support EPA= s choice to use the Acid Rain Program as the vehicle to implement CAIR. Notwithstanding, EPA should establish, and explicitly allow States to establish, higher retirement ratios than those promulgated for SO2 and NOx in order for additional reductions to occur and to help States meet their attainment and transport obligations as required under section 110( a) of the Clean Air Act. [[ ( 2268.1, p. 1) ]]

Response: EPA's legal authority to use title IV allocations under CAIR and its reasons for doing so are discussed in the Notice of Final Action on Reconsideration, Section III. A. EPA did not open for reconsideration the cap levels for SO2.

Document No.: OAR 2003 0053 2282.1 Commenter: South Carolina Public Service Authority and JEA Comment: South Carolina Public Service Authority and JEA are supportive of most aspects of the CAIR, including the CAIR= s overall environmental objective to reduce interstate transport of fine particles and ozone through regional emission limits. However, South Carolina Public Service Authority and JEA are strongly opposed to one key element of the CAIR implementation framework: EPA= s approach of using the statutory title IV Acid Rain Program to implement the CAIR sulfur dioxide ( SO2) reduction requirements and the CAIR SO2 model trading program. [[ Docket number 2282.1, p. 2]] Another serious oversight in EPA= s new analysis is the omission of any evaluation of the environmental impacts associated with the different allowance allocation methodologies. [[ Docket number 2282.1, p. 16]]

Response: EPA appreciates the commenter's support for most aspects of the CAIR, including the overall environmental objective to reduce interstate transport of fine particles and ozone through regional emission limits. Responses to their concerns about the SO2 allocations approach used in CAIR and the environmental impacts related are discussed in the Notice of Final Action on Reconsideration, Section III. A., and in response to comment XVIII. C. 3.

XVIII. H. 3 Document No.: OAR 2003 0053 2271.1 Commenter: National Mining Association Comment: [[ This comment also applies to Outline Heading XIX. G. ]] NMA= s comments are specific to two issues: the fuel adjustment factors used to set state NOx budgets and the SO2 allocation methodology in the CAIR model trading rule. As detailed in the attached, in each case EPA has applied a reasonable allocation methodology that is consistent with statutory requirements. EPA should not make any changes to the CAIR as a result of its reconsideration of these issues. [[ ( 2271.1, p. 1) ]][[ This comment also applies to Outline Heading XIX. G. ]] NMA= s comments focus on the following issues: ( 1) Fuel Adjustment Factors Used To Set State NOx Budgets and ( 2) SO2 Allocation Methodology in the CAIR Model Trading Rules. In each case NMA believes that EPA should not make any changes to the CAIR as a result of its reconsideration of those issues. However, NMA urges EPA to provide additional rationale with respect to both the NOx and SO2 issues along the lines set forth in these NMA comments and as EPA may otherwise develop. [[ ( 2271.1, pp. 2 3) ]] With respect to the SO2 Allocation Methodology, NMA believes the CAIR final allocation methodology represents a reasonable interpretation of the statutory mandate to prohibit SO2 emissions in any state from contributing significantly to fine particle nonattainment in another state. [[ ( 2271.1, p. 3) ]]

Response: EPA thanks the commenter for supporting the aspects of CAIR mentioned above. Additional rationale for NOx State budgets can be found in the Notice of Final Action on Reconsideration, Section III. B, as well as Section XIX of this RTC. Further rationale for SO2 allocations can be found in Notice of Final Action on Reconsideration, Section III. A.

XVIII. H. 4 Document No.: OAR 2003 0053 2279.1 Commenter: Midwest Generation Comment: [[ This comment also applies to Outline Heading XIX. G. ]] Midwest Generation continues to support EPA= s final Clean Air Interstate Rule, generally, and EPA= s inclusion of a cap and trade compliance alternative, in particular. Midwest Generation supports the implementation of a market based approach as the most efficient, cost effective means for achieving sizeable reductions in NOx and SO2 emissions. As set forth in the final rule, the two phase CAIR trading program will assist downwind states with attaining and maintaining applicable PM2.5 and 8 hour ozone National Ambient Air Quality Standards (> NAAQS=) by requiring states in the CAIR region to cap emissions of the relevant precursor emissions  namely, SO2 and NOx. According to EPA= s estimates, the final CAIR= s Phase II caps reflect emissions reductions equal to 3.8 million tons for SO2 and 1.5 million tons for NOx. [[ ( 2279.1, p. 3) ]] The implementation of a CAIR trading program  integrated with other air quality programs such as Title IV= s Acid Rain program and the NOx SIP Call  represents a thoughtful, reasoned approach for maximizing air quality benefits at minimized costs. Under the CAIR trading program, important environmental benefits will be secured by way of caps that limit emissions  absolutely. In contrast to command and control regulation, CAIR= s cap and trade program places absolute limits on SO2 and NOx emissions. And the Phase II cap will not give way to the upward pressures of a growing power generation sector. If power generation increases such that emissions threaten to exceed the caps, sources will have to compensate by achieving increasingly stringent emissions rates. [[ ( 2279.1, p. 3) ]] The model trading program will give sources an economic incentive for achieving reductions greater than those required by the CAIR. Thus, sources that can implement emissions control cost effectively will be encouraged to reduce emissions beyond the requirements of the final CAIR to generate emissions credits which owners can sell or use to bring other of their sources under control. Also, financial incentives created by the CAIR trading program will spur the innovation of increasingly effective and efficient control technology  sources will more readily experiment with unproven approaches to emissions control because they will have a means of compliance should their investment in new technology fail. Finally, the compliance flexibility that CAIR= s cap and trade program provides will enhance overall compliance rates as such programs have in the past. [[ ( 2279.1, pp. 3 4) ]] Based on the foregoing, Midwest Generation affirms its support for EPA= s final CAIR as a sound strategy for emissions reduction in the eastern United States. EPA should not reconsider its fundamental approach  specifically, the inclusion of a cap and trade compliance mechanism  when it reconsiders other aspects of the final rule in response to the Petitions for Reconsideration. [[ ( 2279.1, p. 4) ]]

Response: EPA appreciates the commenter's support for CAIR. Through the final Reconsideration action, EPA maintains the cap and trade system as defined in the final CAIR ( 70 FR 25161).

XVIII. H. 5 Document No.: OAR 2003 0053 2301 Commenter: Pennsylvania Department of Environmental Protection ( PADEP) Comment: The final outcome of EPA= s reconsideration on two aspects of the final rule will have significant impacts on Pennsylvania. The financial harm of failing to exempt or allocate SO2 allowances to previously exempted cogeneration units and waste coal burners will result in the inability of Pennsylvania to efficiently and effectively clean up waste coal piles throughout the state. [[ ( p. 1) ]]

Response: See responses to comment XVIII. A. 1, and XVIII. E. 4, FIP/ 126 final rule, Section VI. E., and FIP/ 126 response to comments, Section VI. A. PADEP did not provide any evidence of their allegations and EPA's analysis shows the contrary.

XVIII. H. 6 Document No.: OAR 2003 0053 2270.1 Commenter: Tennessee Valley Authority ( TVA) Comment: [[ This comment also applies to Outline Heading XIX. G. ]] CAIR imposes a significant challenge to utilities. It requires steep reductions in SO2 and NOx emissions on a very tight schedule. It is a challenge that TVA is prepared to meet and is meeting. We continue to support CAIR as promulgated. TVA does not support changing CAIR as requested by the reconsideration petitions to which EPA is responding. We want to re emphasize our position on two of the issues raised in this reconsideration. [[ ( 2270.1, p. 1) ]] The SO2 allocation method established by the final rule . . . is based on that used in EPA= s highly successful Title IV program for acid rain. It is a method chosen by Congress and using it for CAIR is consistent with congressional policies. This allocation method provides for the permanent allocation of SO2 allowances. The permanent allocation of SO2 allowances facilitates utility system planning and provides an incentive to retire older, less efficient generating units. Replacing the established allocation method would also undermine completed and ongoing state rulemakings implementing CAIR that are based on that method. EPA should retain CAIR= s SO2 allocation method. [[ ( 2270.1, p. 1) ]]

Response: EPA appreciates the commenter's support for CAIR and the SO2 allocation approach as finalized. Through this Notice of Final Action on Reconsideration, EPA is not altering the SO2 allocations approach.

XVIII. I. Comments incorporated by reference XVIII. I. 1 Document No.: OAR 2003 0053 2282.1 Commenter: South Carolina Public Service Authority and JEA Comment: Last year, South Carolina Public Service Authority and JEA provided EPA with a more detailed analysis of some of these issues in comments filed in the proceeding on EPA= s proposed rule to address North Carolina= s Section 126 petition and to establish CAIR Federal Implementation Plans. A copy of the companies= comments from that proceeding is provided in Attachment A to these comments. [[ Docket number 2282.1, p. 2]] See docket number 2282.1, pp 22 28 for Attachment A.]]

Response: See CAIR FIP/ 126 final rule, Section VI. G, and Notice of Final Action on Reconsideration, Section III. A. In order to accentuate this point, EPA has examined the total costs for the three example units brought up by this commenter ( see docket OAR 2003 0053 2282.1 Appendix A). These three units are supposed to represent ( 1) a unit that was clean early and was included in Title IV, ( 2) a similar sized unit that was dirty under Title IV but installs FGD for CAIR, and ( 3) a new clean unit. While the commenter's allowance cost estimations may be reasonable, the overall cost impact is significantly off, since the commenter did not examine capital costs associated installation of the new FGD. For this reason, EPA has performed a more accurate cost estimation for the commenter's three examples, the results of which are shown in the table below. Based on these numbers, EPA concludes that the old previously uncontrolled EGU will bear the greater cost for CAIR compliance than previously controlled EGUs and new clean EGUs because of the incremental expenses of installing and operating an FGD. This runs counter to the commenters' conclusion. ( See Memo from Barry Galef and Jason Lee, ICF Consulting, March 14, 2006 ( Docket: EPA HQ OAR 2003 0053).

Net Impact of the Combined Costs Example 1 Example 2 Example 3 Net Impact of the Combined Costs Phase 1 ($/ MWh) $ 0.68 $ 1.18  $ 3.68 $ 0.41 Net Impact of the Combined Costs Phase 2 ($/ MWh) $ 1.30 $ 2.07  $ 4.73 $ 0.60 XVIII. I. 2 Document No.: OAR 2003 0053 2284.2 Commenter: Minnesota Power Comment: [[ This comment also applies to Outline Heading XIX. H. ]] On August 5, 2005, Minnesota Power had submitted to EPA our Petition for Reconsideration and request for Stay with regard to the final rule entitled, > Rule to Reduce Interstate Transport of Fine Particulate Matter and Ozone ( Clean Air Interstate Rule; Revisions to Acid Rain Program: Revisions to the NOx SIP Call,= which was published at 70 Fed. Reg. 25,162 ( May 12, 2005). Minnesota Power had also submitted previous comments to EPA on matters related to the Clean Air Interstate Rule, including: March 30, 2004, Regarding the Proposed Rule To Reduce Interstate Transport of Fine Particulate Matter and Ozone ( Interstate Air Quality Rule ( IAQR)) published in the January 30,2004, Federal Register; July 26, 2004, Regarding EPA= s Supplemental Proposal for the Rule to Reduce Interstate Transport of Fine Particulate Matter and Ozone ( Clean Air Interstate Rule) published in the June 10, 2004 Federal Register; August 27, 2004, Regarding EPA= s Notice of Availability of Additional Information Supporting the Rule to Reduce Interstate Transport of Fine Particulate Matter and Ozone ( Clean Air Interstate Rule); and May 10, 2005 Regarding a Minnesota Power ( ALLETE) request for correction of data errors related to the characterization of Minnesota Power electric generating units and related emission rates assessed in EPA= s final Rule to Reduce Interstate Transport of Fine Particulate Matter and Ozone ( Clean Air Interstate Rule). These Minnesota Power comments provide supportive information for Minnesota Power= s comments directed towards EPA= s December 2, 2005 Federal Register, CAIR reconsideration request for comments. [[ ( 2284.2, p. 1) ]]

Response: See final CAIR response to comments and Notice of Final Action on Reconsideration preamble section III. C.

XVIII. I. 3 Document No.: OAR 2003 0053 2276.1 Commenter: Duke Energy Comment: Duke Energy strongly objects to EPA= s decision to apportion that budget on the basis of Title IV allowances, as opposed to more recent ( e. g., 1999 2002) heat input values, the basis it used to set the NOx budgets for the CAIR states. The reasons for that objection are detailed in these comments, and in the company= s prior comments, which are incorporated herein by reference. [[ Docket number 2276.1, p. 1]]

Response: See Notice of Final Action on Reconsideration, Section III. A and the Technical Support Document, " SO2 Allocation Approach Analysis."

XVIII. I. 4 Document No.: OAR 2003 0053 2270.1 Commenter: Tennessee Valley Authority ( TVA) Comment: [[ This comment also applies to Outline Heading XIX. H. ]] TVA previously submitted comments on the primary CAIR proposal, published at 69 Fed. Reg. 4566 4650 ( January 30, 2004), by letters dated March 30 and April 5, 2004, and supplemental comments on July 26, 2004. TVA incorporates those comments by reference here. [[ ( 2270.1, p. 1) ]]

Response: See final CAIR response to comments.

XVIII. I. 5 Document No.: OAR 2003 0053 2269.1 Commenter: AES Corporation Comment: These comments supplement our previous comments that were submitted to EPA on July 22, 2004 on the Supplemental Proposal for the Rule to Reduce Interstate Transport of Fine Particulate Matter and Ozone (> CAIR=) that are enclosed and made part of our comments on the Notice of Reconsideration. [[ Docket number 2269.1, p. 1]][[ See docket number 2269.1, pp. 7 14 for previously submitted AES comments ( submitted by Piper Rudnick on behalf of AES Corporation) dated July 22, 2004.]]

Response: See final CAIR response to comments and Notice of Final Action on Reconsideration, Section III. A.

XIX. A. EPA did not provide sufficient notice of use of fuel factor methodology and / or values of factors Document No.: OAR 2003 0053 2290.1 Commenter: Michigan Department of Environmental Quality ( MI DEQ) Comment: The MDEQ believes that EPA failed to provide the background data and information in a timely and adequate manner to the states. This resulted in the inability of states to appropriately address the inequities in the methods used for the fuel neutral calculations. [[ ( 2290.1, p. 1) ]] The EPA indicated that they used fuel adjustment factors ( 1.0 for coal, 0.4 for gas, and 0.6 for fuel oil) when setting state NOx budgets. The EPA also stated that they described this methodology in the proposed and supplemental proposed rules as published in the Federal Register on January 30, 2004 and June 10, 2004, respectively. [[ ( 2290.1, p. 2) ]] However, the actual verbiage in the proposed CAIR states that EPA propose( s) to apply the efficiency standards under Title 18, Section 292.205 to coal, oil, and gas fired units instead of applying the efficiency standards only to oil and gas fired units. The efficiency standard definitions referenced are pursuant to the Federal Energy Regulatory Commission= s Qualifying Facility. The proposed rule did not identify what specific numeric factors would be used. The proposed rule did not indicate how the efficiency standards and fuel adjustments were related; nor did it include text from the section referenced above. [[ ( 2290.1, p. 2) ]] The MDEQ believes that the EPA implied through this language that the efficiency standards were the guiding principles behind the fuel neutral calculations. The Title 28 Section 292.205 regulations do not reference fuel neutrality. [[ ( 2290.1, p. 2) ]] Further, the actual verbiage in the Supplemental Notice of Proposed Rulemaking states, for example, factors could be calculated based on average historic NOx emissions rates by fuel type ( i. e., coal, gas and oil) throughout the proposed CAIR region for the years 1999 2002 at 1.0 for coal, 0.4 for gas and 0.6 for oil. The actual fuel adjustment values were discussed within the SNPR. However, the EPA did not specifically state that these values would be used in the final budget calculations and determinations and only requested comments on possible fuel adjustments. [[ ( 2290.1, pp. 2 3) ]]

The MDEQ believes that the EPA= s obscure and potentially misleading statements in the proposed and supplemental CAIR regulations regarding the efficiency standards and fuel neutral ratios were inappropriate. [[ ( 2290.1, p. 3) ]] The MDEQ further believes that the EPA failed to adequately allow states to review the budget amount differences that occurred using the fuel type ratios. The supporting technical data was not finalized until late March 2005 and not made available to the states until after the final rule was published in the Federal Register on May 12, 2005. States did not have the opportunity to dispute the budget amounts based on the fuel factors or the methods the EPA used to determine subject sources. [[ ( 2290.1, p. 3) ]] The support document referenced above is titled " Technical Support Document for the Clean Air Interstate Rule Notice of Final Rulemaking Regional and State SO2 and NOx Emissions Budgets March 2005" and contains the statement " As is discussed in the Notice of Final Rulemaking ( NFR) . . ." [[ ( 2290.1, p. 3) ]]

In the final rule, the EPA established state NOx budgets using an adjusted heat input method. The specific fuel factors used to adjust heat input data were 1.0 for coal, 0.4 for gas and 0.6 for oil. The EPA further noted that analyses were conducted for state annual NOx budgets established in the CAIR, citing that CAIR also establishes seasonal NOx budgets using the fuel factor approach. [[ ( 2290.1, p. 3) ]] The MDEQ believes that the EPA did not adequately demonstrate the differences between using and not using the fuel adjustment factors. States were not given the data or the opportunity to conduct their own evaluation of the differences between the two levels. States were expected to rely on the EPA= s statement in the final rule that the EPA "... adjusted heat input for type of fuel used. The EPA believes that this method is a reasonable indicator of each state= s appropriate share of the requirements." [[ ( 2290.1, p. 3) ]]

Response: EPA believes that appropriate notice was provided on the use of the FAF methodology and the adjustment factors through the CAIR SNPR and CAIR NFR. However, because of public interest in the issue, EPA granted reconsideration. By requesting public comment through the Notice of Reconsideration, EPA has provided an additional opportunity to the public to comment on the approach and the factors. As a result, EPA believes that all procedural requirements for providing public notice have been fulfilled. Document No.: OAR 2003 0053 2279.1 Commenter: Midwest Generation Comment: Midwest Generation supports EPA= s use of fuel adjustment factors based on fuel type as an important feature of the model trading program that ensures an equitable distribution of the regulatory burden among the regulated community. As a preliminary matter, Midwest Generation notes that EPA provided to all participants in the rulemaking process, including Petitioners, adequate notice that the Agency was considering the use of specific fuel adjustment factors to set state budgets for NOx emissions. Indeed, nearly a year and a half ago, EPA published the Supplemental Notice of Proposed Rulemaking ( SNPR), in which the Agency proposed the model trading rule for SO2 and NOx emissions. With respect to NOx allocations, EPA proposed to determine budgets for states within the CAIR region based on unadjusted heat input data for years 1999 through 2002. However, in that context, EPA suggested as follows:[ t] his heat input data for existing units could be adjusted by multiplying it by different factors based on fuel type, reflecting the inherent higher emissions of coal fired plants. For example factors could be calculated based on average historic NOx emissions rates by fuel type ( i. e., coal, gas and oil) throughout the proposed CAIR region for the years 1999 2000 at 1.0 for coal, 0.4 for gas and 0.6 for oil. 70 Fed. Reg., 32712 ( emphasis added).

The foregoing is sufficient to put all participants to the rulemaking on notice that EPA was considering the use of fuel type multipliers and that, at least informally, it was entertaining multipliers in the range of 1.0 for coal, 0.4 for gas and 0.6 for oil. This is so regardless of the fact that EPA did not invoke the talismanic word " propose" in the SNPR. EPA unequivocally stated that it could use such multipliers, explained the basis on which the multipliers could be calculated and gave specific examples for coal, gas and oil. It would be absurd to read EPA= s statements as anything other than an indication that the Agency was open to comment regarding the formula for setting state NOx budgets. Petitioners offer no sound reason for having disregarded EPA= s statements in the SNPR and foregoing comment until now. In any event, EPA= s reconsideration renders Petitioners= claim of insufficient notice moot. [[ ( 2279.1, pp. 4 5) ]]

Response: The commenter generally supports use of the fuel adjustment factor ( FAF) methodology, the approach taken in the CAIR and CAIR FIP.

Document No.: OAR 2003 0053 2275.1 Commenter: FPL Group Comment: Fuel adjustment factors ( FAFs) should not be used to set state NOx budgets. ( Reconsideration Issue No. 2) While EPA granted reconsideration with respect to its eleventh hour decision to use FAFs to set state NOx budgets, the Notice of Reconsideration states that " EPA believes that it provided adequate notice both that fuel adjustment factors might be used and of the calculation procedures that it would use to determine the specific factors ( 70 Fed Reg 72276). It cites as support for this proposition a discussion of FAFs in the SNPR ( 69 Fed Reg 32689). But the SNPR clearly does not give the notice of EPA= s intent to use FAFs that is attributed to it by EPA. The SNPR simply reports that " commenters have also suggested adjusting the heat input data" with FAFs. Nothing in the SNPR suggests that EPA agreed with those commenters, intended to adopt their proposal, or was soliciting comments on whether doing so would be a good idea. No one could have reasonably anticipated from the SNPR that EPA intended to reverse course and use FAFs to set state NOx budgets in the Final Rule. [[ ( 2275.1, p. 8) ]] FPL Group objects to the use of FAFs to set state NOx budgets for several reasons, as discussed below. ( 2275.1, p. 8) ]]

Response: See response to comment from the Michigan Department of Environmental Quality.

Document No.: OAR 2003 0053 2270.1 Commenter: Tennessee Valley Authority ( TVA) Comment: TVA has addressed this issue in the docket previously. TVA disagrees that notice of this feature of CAIR was lacking or inadequate. In its earlier comments, TVA noted that without a fuel adjustment factor, gas fired generation would essentially be subsidized because it would be allocated allowances at rates above current or projected future emission levels. The purpose of CAIR is to reduce emissions of SO2 and NOx from utilities in support of efforts to attain and maintain the eight hour ozone and fine particle ambient air quality standards. The purpose is not to provide a windfall to states with high gas generation. Providing such a windfall to sources that have no incentive to make reductions undermines the economic basis of cap and trade programs, like CAIR. When subsidized sources dump their emission allowances on the market, they reduce the value of emission allowances which creates a discrepancy with marginal cost of controls. This discrepancy adds uncertainty to control decisions and makes delaying control decisions more economically attractive. EPA should retain its fuel adjustment factors. [[ ( 2270.1, p. 2) ]]

Response: The commenter generally supports use of the FAF methodology, the approach taken in the CAIR and CAIR FIP.

XIX. B. Fuel factor approach unfairly penalizes non coal fired units ( gas and oil units) and / or benefits coal fired units Document No.: OAR 2003 0053 2279.1 Commenter: Midwest Generation Comment: Midwest Generation supports EPA= s use of fuel type adjustment factors to account for differences in the emissions profiles of units that burn coal, gas and oil. EPA= s inclusion of such multipliers appropriately distributes the regulatory burden more equitably among affected sources. If allocations were based on unadjusted heat input data, as EPA proposed in the NPR, the sources that need greater allocations due to the type of fuel they combust would actually receive fewer while sources that need few would be allocated a surplus. For example, coal fired units emit considerably more NOx per Btu than gas fired units. Gas fired sources, on the other hand, emit relatively little NOx per Btu. If allowances are allocated to states based on unadjusted heat input and states pass such allocations on to their EGUs, coal fired sources will have insufficient allowances for complying with the applicable emissions rate and the shortfall will go to gas fired sources that do not need them. As a result, coal fired sources effectively will be required to comply with a more stringent emissions rate. [[ ( 2279.1, pp. 5 6) ]]

To meet the more stringent emissions rate, coal fired sources will have two options, both of which place on them a disproportionate share of the burden for emissions reductions. Coal fired units can install and operate costly control technology in order to meet the more stringent emissions limit. Alternatively, sources that do not meet the emissions rate will be able to purchase allowances from gas fired units that do not need them. Put simply, allocations based on unmodified heat input data tax coal fired sources by subjecting them to greater compliance costs and subsidize gas fired sources by conferring on them a windfall of valuable allowances they do not need. [[ ( 2279.1, p. 6) ]]

Analyses conducted by EPA demonstrate that the use of fuel type multipliers to set allocations helps to ameliorate the disparity. EPA= s region wide analysis shows that under either approach for setting allocations unadjusted heat input or heat input adjusted by fuel type multipliers oiland gas fired units are projected to receive allowances more than sufficient to cover emissions without installation of additional control technology. The fuel adjustment factor approach addresses the inequity by providing additional allocations to states with large numbers of coalfired units that are investing considerable sums in control technology. Moreover, EPA= s state bystate analysis shows that states receiving fewer allocations under a fuel factor approach in most cases still receive statewide budgets greater than emissions projected in 2009 and 2015. In fact, even when allocations are adjusted to account for fuel type, states with greater than 40% gas or oil fired generation generally receive NOx budgets that exceed emissions projections. [[ ( 2279.1, p. 6) ]] The use of unadjusted heat input to set state NOx budgets for the next decade will exact an extraordinary tax from coal fired generation to the benefit of gas and oil fired generation. EPA= s fuel type multipliers minimize the inequity by shifting allowances to sources proportionate to their need. EPA should not change this aspect of CAIR in response to the requests for reconsideration. [[ ( 2279.1, pp. 6 7) ]]

Response: The commenter generally supports use of the FAF methodology, the approach taken in the CAIR and CAIR FIP.

Document No.: OAR 2003 0053 2295.1 Commenter: Tampa Electric Company Comment: TEC supports EPA= s procedure for allocating allowances based on heat input and fuel factors. TEC strongly supports the allocation of NOx allowances on a heat input basis using fuel factors for the following reasons:

a) TEC believes that the use of fuel factors appropriately recognizes that reduced emissions from coal units is technologically more difficult and expensive than for gas units and that coal units require more allowances to operate on a day to day basis than do gas units.

b) Clean coal technology continues to emerge as a significant part of the solution to our nation= s energy problems and provides us with a safe, clean and efficient way to use our nation= s most abundant fuel to produce needed electricity. With the scarcity of natural gas and its skyrocketing prices, it does not appear to us to make sense to provide incentives to continue to burn more natural gas when coal is available and can be utilized in this manner. We believe that the use of fuel factors will further the goal of coal utilization.

c) The elimination of fuel factors would provide a windfall of NOx allowances to natural gas units and require coal units to purchase NOx allowances from natural gas units in order to continue to operate, resulting in increased costs to the customer.

d) It is in the best interest of the State of Florida and the nation to encourage fuel diversity. Providing subsidies through allowance allocations for natural gas generation at the expense of coal is in direct conflict with this concept.

e) Allocating allowances using this fuel based methodology should be encouraged as accurate fuel monitoring and reporting methods are already available.

f) The use of proposed alternative systems to fuel factors directly conflicts with the established SO2 Acid Rain and proposed SO2 CAIR allocation and compliance methodologies. The program should remain simple with baseline allocations, reporting and compliance based on the heat input basis with fuel factors. Otherwise, there would be an unnecessary burden in requiring sources to use different methodologies for SO2 and NOx CAIR compliance. [[ ( 2295.1, pp. 6 7) ]]

In the interest of fairness and consistency, EPA should also encourage the states to use the fuel factor procedure in allocating allowances to the individual sources.[[ ( 2295.1, p. 7) ]] In addition, EPA should uphold the CAIR procedure for allocating allowances based on fuel factors. This enhancement to the initial version of the rule was based on sound judgment and is in the best interest of fairness and promoting the necessary fuel diversity. [[ ( 2295.1, p. 7) ]]

Response: The commenter generally supports use of the FAF methodology, the approach taken in the CAIR and CAIR FIP.

Document No.: OAR 2003 0053 2301 Commenter: Pennsylvania Department of Environmental Protection ( PADEP) Comment: EPA set out initially to base the feasible amount of control an area should contribute based on a " highly cost effective control" determination. Cost effective emission controls for natural gas result in far lower emissions per unit of heat input than for coal or oil units, therefore, it is illogical to determine " highly cost effective control" requirements for gas units based on coal unit metrics a large amount of " highly cost effective control" will be left on the table. In addition, weighting the budgets by fuel simply equalizes the costs of the control effort contribution each type of unit can and should make. [[ ( p. 2) ]]

A fuel neutral budget allocation would give natural gas units and states with large natural gas resources and generating capacity huge allowance and financial windfalls. This would result in both an inequitable economic transfer of wealth between states as well as inadequate emission control within and adjacent to the Northeast corridor. EPA should retain the current fuelweighted methodology. [[ ( p. 2) ]] Natural gas consumption estimates for 2003 as reported by the Energy Information Agency, and considering only those states in the CAIR program, indicate that the largest amount of natural gas consumed for electricity production occurred in Texas at 1483.8 trillion Btu of natural gas, Florida at 553.5 trillion Btu, North Carolina at 267.1 trillion Btu, and Louisiana at 244.1 trillion Btu. In comparison, Pennsylvania used only 42.8 trillion Btu, Ohio used 19.4 trillion Btu, Indiana used 27.2 trillion Btu, Virginia used 36.2 trillion Btu, West Virginia used 2.2 trillion Btu, Tennessee used 5.8 trillion Btu, and Kentucky used 3.8 trillion Btu.

When using a fuel neutral approach, the implications and results of the disparity result in large amounts of allowances controlled by a few natural gas intensive states or a small number of corporations in those states. There could be a significant transfer of wealth from coal states to natural gas states with little benefit for the air in the Northeast. The Commonwealth supports EPA= s fuel based state allocation process and the state budgets as proposed. [[ ( pp. 2 3) ]]

Response: The commenter generally supports use of the FAF methodology, the approach taken in the CAIR and CAIR FIP.

Document No.: OAR 2003 0053 2272.1 Commenter: Cinergy Corp. Comment: Cinergy supports the use of fuel type multipliers for purposes of calculating statewide NOx allowance budgets. Heat input allocations that distribute allowances based on each unit= s pro rata share of heat input alone inappropriately disadvantage coal fired EGUs. Coal fired units emit more NOx per Btu than gas fired units, for example. If allocations to coal fired units are based on heat input alone, rather than weighted according to fuel type, coal fired units will not receive allowances sufficient to meet the relevant NOx emissions rate on which CAIR is based. Instead, the shortfall of allowances to coal fired units will go to gas fired units, which intrinsically emit less NOx per Btu and, therefore, do not need the additional allowances. To compensate, coal fired sources will be required to comply with an emission rate that is more stringent than the highly cost effective basis for the rule. Alternatively, coal fired units that do not meet the emissions rate may purchase additional allowances from gas fired units that do not need them. This unmodified heat input allocation methodology produces a windfall for sources that do not combust coal and simultaneously imposes greater compliance costs on coal fired units. There is no policy reason to support what amounts to little more than a transfer of wealth. The use of fuel type adjustment factors ensures that the regulatory burden namely, costs for compliance is distributed equitably among affected sources. [[ ( 2272.1, p. 3) ]]

To assess the wealth transfer effect that would result from unadjusted allocations, Cinergy= s engineers used EPA= s data to calculate the effective emissions rates for gas fired units within the CAIR region  first, assuming no fuel type adjustment, and once again, incorporating EPA= s multipliers. Our internal analysis shows that, if EPA= s multipliers are used, gas fired units must meet, on average, an effective emission rate of approximately 0.065 lb/ mmBtu. Although this may seem extraordinarily low, in fact, it closely approximates what most gas fired combustion turbines currently achieve without the installation of additional control equipment. In other words, it will cost gas fired units very little to comply with the rule, even if it includes the fueltype multipliers. [[ ( 2272.1, p. 3) ]]

In contrast, if the multipliers are eliminated, gas fired units will be required to meet, on average, an effective emission rate of approximately 0.14 lb/ mmBtu. This rate is significantly higher than the emission rate currently achieved by the majority of gas fired units and, thus, amounts to nothing more than a windfall of allowances that companies can sell for profit or use to cover emissions at their non gas fired plants. Coal fired units, however, will be required to expend significant resources to comply with this rule even if the fuel type multipliers are used. If EPA eliminates these multipliers, costs to coal fired units will increase  while valuable allowances will be allocated to sources that do no need them. As noted above, no policy would justify EPA= s grant of an allowance windfall to gas fired units. [[ ( 2272.1, pp. 3 4) ]] The results of our internal analysis are consistent with additional analyses that EPA conducted in response to the requests for reconsideration.

Petitioners argue that the fuel adjustment factors penalized gas fired units and should be eliminated. In response, EPA conducted two analyses to evaluate the impact of using fuel multipliers versus no multipliers, both on a region wide scale and on a state by state basis. The Agency= s analysis demonstrates that both gas and oil fired units will get the allowances they need to operate  without installing control equipment  even if allocations are adjusted to account for fuel type. Thus, EPA= s analysis supports the conclusion that there is no reason to modify the fuel adjustment factors. That is, CAIR is not supposed to be a " freebie" for non coalfired units, but EPA= s analysis shows that gas fired units are unlikely to experience any shortfall in allowances  and at most will experience a small shortfall. Yet even if these units encounter a small allowance shortfall with these fuel adjustment factors, that surely does not support changing the factors given the enormous reductions ( and costs) that must be borne by coal fired units. [[ ( 2272.1, p. 4) ]]

EPA also specifically concluded that, where a fuel adjustment of 0.4 is applied to gas fired units, the portion of the State budgets derived from the heat input from the gas fired units generally exceeds both the historical and the future projected emissions from these units. Indeed, EPA= s analysis shows that states with greater than 40% gas or oil fired generation generally receive NOx budgets that exceed their projected emissions. Major coal burning states, in contrast, must make dramatic NOx emission reductions under CAIR. For example, CAIR represents annual NOx emissions reductions of 48% and 66% in Indiana for 2009 and 2015, respectively; in Kentucky of 44% and 58%, and in Ohio of 66% and 67%. EPA= s analysis demonstrates that even using a multiplier of 0.4, virtually none of these reductions will be borne by gas fired units; rather, coal fired units will make dramatic reductions and gas fired units will do almost nothing. [[ ( 23272.1, pp. 4 5) ]] Under such circumstances, it makes no sense for EPA to provide an additional windfall to gas fired units. Such a shifting of allowances away from coal fired generation, when multiplied by the estimated price for NOx allowances and added over a 10 year period, amounts to a substantial penalty to coal fired generation and an equally substantial subsidy to gas fired generation. Again, there is no policy justification for granting such an allowance windfall to gas fired units. [[ ( 2272.1, p. 5) ]] Response: The commenter generally supports use of the FAF methodology, the approach taken in the CAIR and CAIR FIP.

Document No.: OAR 2003 0053 2275.1 Commenter: FPL Group Comment: The use of FAFs is inconsistent with the approach used by EPA to determine the regional NOx budget. For the CAIR region, EPA determined how much baseline emissions would be reduced by the installation of cost effective controls. At a meeting on November 30, 2005, EPA acknowledged to FPL Group that it considered controls to be cost effective only on coal fired EGUs. However, the FAFs will result in ratcheting down the allowances available in states with a high proportion of non coal EGUs to the extent that EGUs in those states will be forced either to install pollution controls that are not cost effective, or else to buy expensive allowances in spite of the fact that they are cost effectively controlling their emissions. This problem will be exacerbated for non coal EGUs in states that also apply FAFs to allocate their budgeted NOx allowances to particular types of EGUs, as Florida currently proposes to do. [[ ( 2275.1, p. 8) ]]

In the Notice of Reconsideration, EPA defends the use of FAFs essentially by arguing that coal EGUs need to be subsidized to offset the greater burden on them of complying with CAIR= s emission reductions. This rationale is untenable. Consciously subsidizing coal EGUs would be unfair and counter productive.[[ ( 2275.1, p. 8) ]]

FAFs are an economic subsidy that coal fired EGUs do not need or deserve. The fuel cost for coal EGUs is much lower than for oil or gas EGUs. The cost spread has become even wider recently. Using EPA and United States Department of Energy ( DOE) data, FPL Group has calculated an average delivered fuel cost for Florida= s coal EGUs of= about $ 1 l/ MWh in 2010, whereas the average delivered fuel cost for gas EGUs will be about $ 36/ Mwh in that same year. This is a difference of approximately $ 25/ Mwh In contrast, EPA has estimated that the retail cost of electricity will increase by about $ 3 90 Mwh as a result of implementing CAIR, as well as EPA= s Clean Air Mercury Rule and the Clean Air Visibility Rule See Multi Pollutant Regulatory Analysis CAIR/ CAIR/ CAIR, EPA Office of Air and Radiation, October 2005. Clearly, the differential cost to coal and gas EGUs of complying with CAIR will not be as large as this $ 3.90 Mwh total compliance cost, but even if it were, the fuel cost differential is more than six times as great. [[ ( 2275.1, pp. 8 9) ]]

Moreover, using FAFs to subsidize coal EGUs would be economically inefficient. Economic efficiency dictates that EGUs with the lowest overall operating costs should be built and operated preferentially. Operating costs consist of several components, including both the cost of fuel and the cost of pollution control. The use of FAFs effectively taxes oil and gas EGUs and transfers the proceeds to coal EGUs to help them pay for their higher costs of pollution control. This tax sends an artificial price signal that coal fired plants are cheaper to build and operate than they actually are. It is no different from an economic perspective than taxing EGUs and transferring the proceeds to oil and gas EGUs to help them pay for their higher priced fuel. EGUs should be evaluated on the basis of their actual costs the cross subsidies that will result from the FAFs interfere with that goal. [[ ( 2275.1, p. 9) ]] Finally, EPA has made an erroneous assumption about the impact of CAIR on Florida that invalidates EPA= s conclusion that Florida would be a winner under CAIR with or without FAFs. Tables 1, 2 and 3 in the Notice of Reconsideration purport to show that states such as Florida with a high percentage of non coal EGUs will have more NOx allowances than they will need to accommodate the emissions from their EGUs, once cost effective CAIR emission controls have been installed. They suggest that this is so with or without FAFs. From this analysis, EPA then concludes that transferring NOx allowances to states with a high percentage of coal EGUs is fair because it distributes the burden of CAIR compliance more equally. The analysis upon which these tables are based excludes numerous older oil and gas EGUs from the base case emissions used to establish the NOx allocations, on the assumption that those EGUs will no longer be operated by the time the CAIR budgets become effective. [[ ( 2275.1, p. 9) ]]

For Florida in general and FPL Group in particular, this assumption is incorrect and it results in a major misrepresentation of the > fairness= of the CAIR NOx budgets to Florida and to FPL Group. EPA apparently assumes that the older oil and gas EGUs will be retired because they are not as cost effective to operate as either coal EGUs or combined cycle gas EGUs. In fact, high growth states such as Florida do not have the luxury of retiring older less efficient EGUs as they build new ones: both the old and new units are needed to meet rapid load growth. Illustrative of this point is A Review of Florida Electric Utility 2005 Ten Year Site Plans, prepared by the Florida Public Service Commission in December 2005 and attached hereto as Attachment 6 ( the TYSP Review). The TYSP Review summarizes the types of generating resources with which each electric utility in Florida intends to meet its customers= demand for electricity over the period 2005 to 2014. One of the generating resource types is > fossil steam, which comprises older oil and gas EGUs, as opposed to the more modern combined cycle gas EGUs. The TYSP Review shows that Florida currently has 9.890 MW of fossil steam EGUs in service and that this total will be reduced only by 41 MW ( about 4%) over the period ending 2014. [[ ( 2275.1, pp. 9 10) ]]

Clearly, EPA= s assumption that most of the older, fossil steam units will be retired is wildly off target. If one were to correct Table 2 for this inaccurate assumption about retiring older oil and gas EGUs, the CAIR emissions for Other Fossil EGUs in Florida would increase from 17,000 tons per year of NOx to approximately 70,000 to 75,000 tons, which is well above both the 58,000 tons that is shown for a " simple heat input budget" and the 34,000 tons that is shown for the > fuel adjusted budget=. Moreover, Florida= s total CAIR emissions would increase from 69,000 tons to about 124,000 tons, which exceeds even the > simple heat input budget of 116,000 tons and is well above the > fuel adjusted budget of 99,000 tons. [[ ( 2275.1, p. 10) ]]

Thus, even without FAFs, utilities in Florida will have to buy a large number of expensive allowances in order to operate their older oil and gas EGUs and that this burden will be even greater if FAFs are used. This is in spite of the fact that those older oil and gas EGUs inherently have lower emissions than coal EGUs FPL Group fails to see how the use of FAFs could possibly be said to increase fairness in this situation. [[ ( 2275.1, p. 10) ]]

Beyond the issues of fairness and economic efficiency, the use of FAFs also calls into question the entire premise for CAIR. The rule is not about reducing SO2 or NOx emissions generally throughout the CAIR region; rather, CAIR is targeted at ( and justified by) reducing impacts on specific downwind non attainment areas by specific upwind states. EPA determined what the impact of CAIR would be on downwind non attainment areas by modeling the impact of costeffective emission reductions throughout the regulated upwind states. That modeling did not assume the use of FAFs to redistribute the allowable emissions among those upwind states. So far as FPL Group can discern from the CAIR rulemaking record, EPA has not determined the effect of FAFs on those modeling results. Unless and until it does so, EPA cannot be confident that CAIR will work as intended if it uses FAFs to redistribute the regional NOx budget among the upwind states. [[ ( 2275.1, pp. 10 11) ]]

EPA= s efficient trading markets theory does not allay this concern. It may be true that NOx allowances will ultimately end up in the hands of the EGUs that most need them, regardless of where those allowances are initially allocated. However, the decrease in operating costs for EGUs in states that are rewarded by the FAFs could result in additional electric output and thus higher emission levels in those states. Without additional analysis and modeling, EPA cannot how where and to what extent this shift in emissions will occur or what the impact would be on downwind non attainment areas. Simply put, using FAFs to allocate state NOx budgets without further analysis of their impact invalidates the analytical rationale for CAIR. EPA must either reallocate the NOx budgets without using FAFs or start over again in its modeling of the impact of CAIR on downwind non attainment areas. [[ ( 2275.1, p. 11) ]]

Response: EPA disagrees with the commenter's claim that use of the FAF methodology subsidizes coalfired generation. In fact, the use of the FAF methodology provides allowances to types of generation that is more proportionate to their projected investment in advanced emission controls as a result of CAIR. If EPA provided allocations to gas fired units, which typically have NOx emission rates much lower than coal units, using a simple heat input approach ( non FAF approach), then the gas fired units would have and even greater excess of NOx allowances to sell to the coal fired generation ( i. e., the units that are projected to invest in advanced emission controls), effectively subsidizing gas units. By using a FAF approach, EPA has chosen to use a system that reduces disparity between the projected emissions and the budgets, and avoids subsidizing any one type of generation.

EPA disagrees with the commenter's contention that the use of FAF methodology to apportion CAIR NOx budgets to the States would significantly impact States with predominantly gas fired generation. Analysis presented in the CAIR Notice of Reconsideration ( December 2005) demonstrated that use of the FAF methodology is reasonable and generally decreases the disparity between most States' projected emissions and statewide NOx budgets. More specifically, EPA presented analysis in the CAIR Notice of Reconsideration that showed that States with predominantly non coal fired generation would have budgets that are greater than their projected emissions in 2009 and 2015. In the case of Florida, the analysis showed that they would have coverage ratios of 1.45 and 1.35 under CAIR in 2009 and 2015, respectively. In other words they have allowances equal to 145% and 135% of their projected emissions in 2010 and 2015, respectively.

EPA modeling in support of CAIR included gas and oil fired units and demonstrated that highly cost effective NOx emission reductions are available from the power sector. The marginal cost of control and the average cost of control, shown to be " highly cost effective," reflect a range of power sector control costs that include costs from sources such as older gas and oil fired units. In projecting which units will operate, the model considers where control will be least expensive and that some units will purchase allowances. The market provides a mechanism to find least cost reductions, so that units that would have a high cost of control, can choose to purchase allowances from other sources at a price below their control costs.

EPA disagrees with the commenter that it is inappropriate to provide additional allowances to States with predominantly coal fired generation because they will make the largest investment in advanced emission controls under the CAIR. EPA analysis has shown that the use of the fuel adjustment factor ( FAF) methodology reduces the disparity between the projected emissions in predominantly coal fired States and their budgets. EPA believes it is appropriate to consider which types of sources are making reductions for the CAIR. EPA disagrees with the commenter's assertion that in determining the cost of compliance CAIR, the cost of historical decisions   such as the decision to build a gas or oil fired plant in the past   should be considered as part of CAIR.

EPA disagrees with the commenter that the use of FAF or simple heat input methodologies for apportioning the region wide NOx emissions budgets to the States will significantly impact the air quality modeling results. Because allowances can be traded across the entire region, the market may find the least cost reductions regardless of where the allowances are initially allocated. That is, sources that can reduce their emissions for the least cost will do so whether they are avoiding having to purchase an allowance or reducing their emissions and selling an allowance to offset the control costs. In this case, the use of an allowance, whether it is purchased or whether it is an opportunity cost, is a cost to the unit. As a result, the air quality modeling, and subsequent findings of significant contributions, will not be significantly changed by the approach taken for the apportionment of the region wide budget. EPA has over 15 years of experience with market based cap and trade programs, and with the use of different allocation methods. Markets continue to operate efficiently. Sources may choose from many alternatives for reducing emissions, including installing pollution control equipment, switching from highsulfur coal, employing energy efficiency measures and/ or renewable generation, and buying excess allowances from other sources that have reduced their emissions, or using a combination of these options. The flexibility of compliance options afforded sources has lead to advancements in technology and costs continuing to go down. A cap and trade system allows companies to choose the lowest cost compliance option. Cap and trade programs are a proven mechanism to deliver and sustain significant mandatory emission reductions and have been recognized worldwide as a model for flexible and effective air pollution regulation. Through cost effective, market based approaches, environmental and economic interests can be aligned rather than at odds.

EPA disagrees with the commenter that our analysis is flawed because we under project the operation of existing inefficient gas and oil fired units, and therefore under project future emissions from those units. As noted above, EPA's modeling does, in fact, include the generation and emissions of older gas and oil fired units. For Florida, the CAIR analysis indicated that only 23 percent of these units would be retired with the remainder of these units in reserve capacity. Based upon information submitted by the commenter, Florida maintains a reserve margin of at least 20 percent ( and as high as 28 percent) in order to meet annual peak demand, allow for flexibility in which units are dispatched, allow for growth in demand, and allow for some routine outages. 4 As a result, if these existing oil and gas fired units were to remain in the generation fleet, they would likely be part of the reserve capacity that would operate infrequently. If EPA modeling results for these infrequently operated units differed from their future dispatch, they would likely not significantly change the statewide emission projections due to their low total emissions.

In addition, should these uneconomical units stay in operation as the commenter contends, they have a several emission control options available to them. While EPA modeling suggests that most cost effective controls on coal fired plants, this does not mean that there are not " highly cost effective" control options for other types of units. There are limits to the number of control options that considered in a model and, because there are significantly less options for existing oil and gas fired boilers, EPA has not provided as wide a range of control options for these units. However, EPA analysis has shown that some gas and oil fired units have already achieved emission rates as low as 0.18 lbs/ mmBtu and 0.16 lbs/ mmBtu, respectively, without having to install post combustion controls. 5 ( EPA notes that IPM does not model the installation of these non post combustion control strategies.)

While the commenter has claimed that existing oil and gas fired units would remain in service, they have not provided evidence to substantiate it. The commenter cites " A Review of Florida Electric Utility 2005 Ten Year Site Plans." However, this report is a collection of information provided by the power companies. The report caveats the information provided by saying " the Ten Year Site Plans are not a binding plan of action on electric utilities" and continues that " the Ten Year Site Plans are planning documents containing tentative data." Even so, the commenter provided report shows that oil and gas fired capacity ( identified by the commenter as the " oil and gas fossil steam" category) oil and gas fired units were projected to dramatically decline in the 2004 forecast, with the 2005 forecast changing to show a slight increase in capacity   showing the volatility in forecasts of this nature. This 2004 forecast of commenterprovided report is consistent with actual data reported to EPA under the Acid Rain Program showing that operation of the existing oil fired units in Florida shows a declining trend for the years 2002 through 2005.6 In summary, the commenter has not provided conclusive information of their claim that these existing gas and oil fired units would remain in service. Further, the commenter has not shown that, should some of these existing units remain in the fleet, they would operate and emit at levels that would significantly change to EPA analysis of the coverage ratios.

4 The commenter cites " A Review of Florida Electric Utility 2005 Ten Year Site Plans" that may be found as an attachment to the Florida Power and Light comments in the docket for today's rulemaking. 5 EPA analysis of data submitted under the Acid Rain Program. See spreadsheet " Florida Emission Rates Oil Gas Units" in the docket. Emission rates are for combustion control strategies ( i. e., low NOx burners, combustion modification, or over fire air technologies) other than the installation of post combustion controls. Emission rates are for application to boilers and lower emission rates can be expected if installed on simple cycle turbines. In general, combustion controls are less expensive than installing advanced controls. 6 Data reported to EPA under the Acid Rain Program shows that, for Florida oil fired units, heat input declined from approximately 408 million mmBtu in 2002 to 378million mmBtu in 2005. Document No.: OAR 2003 0053 2268.1 Commenter: Northeast States for Coordinated Air Use Management ( NESCAUM) Comment: Fuel adjustment factors used to set State nitrogen oxides ( NOx) budgets: EPA has chosen to adjust heat input data for allocations based on factors that reflect the inherently higher emissions rate of coal fired plants. EPA= s adjustment factors favor the sources with the highest emitting fuel and disregard the economic impact of having fewer allowances allocated to States where electricity costs are already higher, in some part, due to a higher percentage of cleaner natural gas facilities. We disagree with this approach as it effectively results in allowance subsidies for the biggest polluters. States that have already benefited from lower electricity prices because of the lack of controls on coal fired units are now rewarded with additional allowances, and States that have more energy efficient facilities are penalized because the allocation to States is based on heat input. While gas fired plant owners have been paying for cleaner fuel, under EPAs chosen approach, they may be penalized with the additional cost of purchasing allowances in order to comply with CAIR. Such costs would be passed on to ratepayers in the form of higher electric rates. Furthermore, EPA= s use of fuel adjustment factors would not only discourage investment in new cleaner natural gas electric generating units, but also discourage investment in new cleaner coal fired electric generating units such as Integrated Gasification Combined Cycle ( IGCC) technology. In addition, EPA= s approach locks States with a lower percentage of coalfired generation into a lower budget that may not accurately account for future emissions under different conditions ( e. g., increasing natural gas prices). EPA should revert to the fuel neutral budget calculation methodology it proposed for CAIR ( 69 FR 4566) so that cleaner, more efficient sources are not at a disadvantage in the budget setting process. [[ ( 2268.1, pp. 1 2) ]]

Response: EPA disagrees with the commenter for reasons explained in the response to the Connecticut Department of Environmental Protection. In addition, EPA disagrees with the commenter's assertion that the use of a FAF methodology would " discourage investment in new cleaner coalfired electric generating units such as Integrated Gasification Combined Cycle ( IGCC) technology." EPA notes that the commenter did not provide analysis to support this claim. Further, EPA believes that the use of a cap and trade approach inherently provides incentives for sources to generate electricity while emitting less.

Document No.: OAR 2003 0053 2271.1 Commenter: National Mining Association Comment: EPA= s application of equitable concerns is logical and in compliance with the statute. Entergy is mistaken in claiming that use of the fuel adjustment factors is supported by no more than EPA= s subjective view of the equities. As seen, the fuel adjustment factors are firmly rooted in the statute. Nevertheless, use of the fuel adjustment factors is also equitable. EPA partially relied on equity in justifying the factors and that reliance is authorized by the statute. [[ ( 2271.1, p. 11) ]] In its December 2, 2005 Notice of Reconsideration, EPA aptly described the equitable factors supporting the fuel adjustment factors. Because coal plants have inherently higher emission rates, there is a greater burden on them to control emissions. The fuel adjustment factors would not penalize coal plants that had already installed pollution control equipment. Assuming states allocate allowances to sources in the same way they are allocated to the states gas fired units still generally receive more allowances than they need to operate. Use of the fuel adjustment methodology reduces the disparity between the number of allowances provided and emissions as compared with the simple heat input method. As EPA found the fuel factor approach generally provides additional allowances to States with large amounts of coal fired units that are making the investments in emission control measures and technologies. Conversely, the simple heat input approach provides more allowances to States with larger amounts of gas fired units that are not making reductions. EPA= s results did not change even when tested against different scenarios of electricity demand and gas and oil prices. [[ ( 2271.1, pp. 11 12) ]]

These types of equitable considerations fit comfortably within the cost benefit analysis that the Michigan Court endorsed under Section 110( a)( 2)( D). The Michigan Court determined that the word " significant" in the phrase " significant contribution" expressed Congress= s intent that EPA balance costs and benefits in determining controls states would be required to implement. According to the Court, EPA may consider cost that go beyond simple dollar per ton control costs and include non health tradeoffs. The Court= s discussion is plainly framed in traditional cost benefit terms, where the benefits of the regulation are weighed against the costs to society of achieving those benefits. The equitable considerations underlying the fuel adjustment factors are societal costs that EPA properly considered in weighing the > significance= of an individual state= s contribution to downwind nonattainment. [[ ( 2271.1, p. 12) ]] Indeed, both the NOX SIP Call and CAIR as proposed in the NOPR were based on equitable considerations that affect the cost and feasibility of complying with those programs.

Both programs considered the feasibility of controls ( in terms of available labor, capital, materials and equipment) in establishing the level of highly cost effective controls and the deadlines for complying with the programs. In determining highly cost effective controls under CAIR, EPA stated: The second major factor that EPA applies is the cost factor. EPA interprets this factor as mandating emissions reductions in amounts that would result from application of highly cost effective controls. We ascertain the level of costs as highly cost effective by reference to the cost effectiveness of recent controls. As we stated in the CAIR NPR, in determining the appropriate level of controls, we considered feasibility issues as we did in the NOX SIP Call. Specifically, the applicability, performance, and reliability of different types of pollution control technologies for different types of sources, and other implementation costs of a regulatory program for any particular group of sources ( NPR, 69 FR 4585).

That rationale applies to the use of fuel adjustment factors, which reduce the burden of compliance with the program by those sources, i. e., coal fired units that will be required to make the lion= s share of emissions reductions. Using these factors promotes program feasibility, a goal of both the NOX SIP Call and the CAIR NOPR. [[ ( 2271.1, p. 13) ]] EPA in both the NOX SIP Call and the CAIR NOPR also explicitly recognized the role of equity. As with the NOX SIP Call, EPA considers other factors that influence the application of the air quality and cost factors, and that confirm the conclusions concerning the amounts of emissions that upwind States must eliminate as contributing significantly to downwind nonattainment. Specifically, as we stated in the CAIR NPR " We are striving in this proposal to set up a reasonable balance of regional and local controls to provide a cost effective and equitable governmental approach to attainment with the NAAQS for fine particles and ozone" ( See 69 FR 4612). In this manner, we broadly incorporate the fairness concept and relative cost of control ( regional costs compared to local costs) concepts that we generally considered in the NOX SIP Call ( 70 Fed. Reg. 25,175.) In sum, EPA= s use of equity to justify the fuel adjustment factors is authorized by the statute.

Response: The commenter generally supports use of the FAF methodology, the approach taken in the CAIR and CAIR FIP.

Document No.: OAR 2003 0053 2281.1 Commenter: Northern Indian Public Service Company ( NIPSCO) Comment: The problems of inequity are not present in the CAIR NOx trading programs. The approach in the NOx trading programs is based upon a more recent baseline, is not rooted in the Acid Rain Program, and is more relevant to today= s emissions and air quality circumstances. It is poor regulatory policy to reward coal fired sources that have not taken steps to reduce emissions, and at the same time effectively punish low emitters who have already invested in equipment to reduce emissions from their coal tired units. It sends the wrong message. It discourages actions on the parts of industry and states to reduce emissions or require reductions before USEPA has decided to address the air quality issue. Historically, USEPA has recognized and given credit for actions taken by a source or state to reduce emissions after a baseline year. USEPA is following this laudable approach in the 8 hour ozone Phase II Implementation rule. However, USEPA is effectively departing from this approach in the CAIR SO2 program by clinging to the Acid Rain Program in the manner it has. The analyses USEPA performed during its reconsideration should have demonstrated this point.

Response: The commenter generally supports use of the FAF methodology, the approach taken in the CAIR and CAIR FIP.

XIX. C. EPA did not properly analyze regionwide or state by state impacts of using fuel factor approach ( both preamble and TSD)

Document No.: OAR 2003 0053 2282.1 Commenter: South Carolina Public Service Authority and JEA Comment: EPA correctly asserts in its analysis of the methods for setting state NOx budgets that there is a strong public interest in an allocation method that has the lowest possible disparity between the allowances provided to a state and the state= s projected emissions. South Carolina Public Service Authority and JEA believe that, in the Notice of Reconsideration= s discussion of the issue of state NOx emission budgets, EPA has used the correct criteria and analytical approach to evaluate the reasonableness of its methodology against alternatives: ( 1) whether the EPA method avoids penalizing coal fired generation units that already have installed emission controls and ( 2) whether, relative to the alternatives, the EPA method better minimizes for each state the disparity between allowances provided and projected emissions. On these bases, EPA concludes that its method  which is based on recent heat input data adjusted for fuel type is the most rational approach. [[ Docket number 2282.1, p. 4]][[ See docket number 2282.1, pp4 6 for further discussion of this issue.]]

Response: The commenter generally supports use of the FAF methodology, the approach taken in the CAIR and CAIR FIP.

Document No.: OAR 2003 0053 2290.1 Commenter: Michigan Department of Environmental Quality ( MI DEQ) Comment: Additionally, the MDEQ believes that EPA failed to properly count the total number of subject units within the state, therefore underestimating Michigan= s budget, to the detriment of the utilities and their operations. [[ ( 2290.1, p. 1) ]] The MDEQ has reviewed the data that the EPA provided and believes that since Michigan was a partial state during the NOx SIP Call process, the EPA failed to account for all the sources in the state when they calculated the budgets. The EPA= s data indicates that only 130 units were included in the calculations. Michigan data indicates there are 155 units that should have been included in the calculations. The MDEQ previously requested more information regarding this issue on October 12, 2005 through an email sent to both EPA Region 5 and Clean Air Markets Division staff. See Table 1 that lists Michigan sources. [[ ( 2290.1, p. 3) ]] [[ ( Table 1 can be found on p. 4 of docket number 2290.1) ]] The MDEQ believes that the budget amounts for Michigan should be corrected and adjusted upwards to account for the 16 percent of units that the EPA failed to include in their calculations. The MDEQ believes that the NOx CAIR ozone season budget should be adjusted upwards, as indicated in Table 2 below. [[ ( 2290.1, p. 3) ]] [[ ( Table 2 can be found on p. 5 of docket number 2290.1) ]]

Response: EPA disagrees with the commenter that Michigan's heat input used in the determination of budgets should be adjusted to reflect concerns the MI DEQ recently communicated to EPA. The commenter notes that they " requested more information regarding this issue on October 12, 2005 through an e mail sent to both EPA Region 5 and Clean Air Markets Division staff." EPA is taking comment through this rulemaking on only certain aspects and is not opening for comment other aspects, such as the heat input used to establish regionwide or statewide budgets, that were finalized in the CAIR NFR. As a result, EPA is not revising the Michigan's heat input data used to establish CAIR budgets. However, EPA has been working with the States to improve unit inventories to be used in other, future processes, such as applicability determinations and the development of unit by unit allocations. EPA looks forward to continuing to work with States to improve the information used in the implementation of the CAIR.

In setting budgets, EPA used data reported to EPA under title IV, supplemented by data reported to EIA for units that do not report to EPA. Data from both these sources cover the entire State of Michigan, not just the portion of the State covered by the NOx SIP Call. Document No.: OAR 2003 0053 2271.1 Commenter: National Mining Association Comment: EPA has determined each state= s NOx budget as a pro rata share of a region wide, annual cap on NOx emissions. Initially, in the proposed rulemaking, each state= s share was calculated as the ratio of that State= s annual heat input to the CAIR region= s annual heat input. Subsequently, in the final CAIR rule, the Agency revised its method for calculating each state= s share by first adjusting that state= s heat input from each fuel type by a fuel adjustment factor for that fuel type, and by then dividing the State= s aggregate adjusted heat input by the CAIR region= s aggregate adjusted heat input. [[ ( 2271.1, pp. 3 4) ]]

Petitioner Entergy Corporation ( Entergy) asserts that EPA= s fuel adjusted heat input methodology exceeds the Agency= s authority under Section 110( a)( 2)( D) of the Clean Air Act. Entergy= s primary argument is that EPA= s methodology contradicts EPA= s determination that the amount of each state= s emissions reduction should reflect the use of > highly cost effective= controls on EGUs and is otherwise not authorized by the statute. Entergy claims that use of the fuel adjustment factors is based on no more than EPA= s > subjective view of the equities= and has no relationship to the air quality objectives of the statute. [[ ( 2271.1, p. 4) ]] Entergy is mistaken. As shown below:

( 1) use of the fuel adjustment factors is neither arbitrary nor capricious but rather is in accordance with the statutory command of Section 110( a)( 2)( D) that each state eliminate its significant contribution to nonattainment in a different state;

( 2) as a reasonable interpretation of its authority under Section 110( a)( 2)( D), EPA= s decision to use fuel adjustment factors will be entitled to deference by a reviewing court;

( 3) EPA= s partial reliance on equitable considerations was reasonable and in accordance with the statute; and ( 4) use of the fuel adjustment factors promotes rather than undermines the air quality purposes of the statute. [[ ( 2271.1, pp. 4 5) ]] The fuel adjustment factors accord with Section 110( a)( 2)( D). In the NOPR, EPA computed a State= s NOx budget based upon its pro rata share of the CAIR region= s annual heat input. Under this approach, each state= s annual NOx emission rate from EGUs under the CAIR would have been the same as the region wide, average annual emission rate from EGUs, i. e., 0.125 lb/ mmBtu in 2015 ( 0.15 lb/ mmBtu in 2009). [[ ( 2271.1, p. 5) ]]

Entergy claims that EPA= s original approach is the only rational way to determine a state= s NOx budget consistent with the statute. According to Entergy, unless state NOx budgets are set according to a straight heat input method ( and therefore each state is effectively subject to the same annual NOx emission rates), there can be no assurance that emission reductions required in each state will reflect the use of highly cost effective controls on EGUs. [[ ( 2271.1, p. 5) ]] Entergy= s view of the fuel adjustment factors is incorrect. In fact, EPA= s adoption of the fuel adjustment factors in the final CAIR is a more accurate method of ensuring that CAIR emissions reductions are set according to the statutory " significant contribution" standard than EPA= s original approach in the CAIR NOPR. This is because the final rule methodology, unlike the NOPR approach, accounts for the fact that each state has a different mix of coal, oil and gas EGUs.

Because of these differing fuel mixes, application of highly cost effective controls on a state bystate basis will logically yield different emission reduction profiles among the different states. [[ ( 2271.1, p. 5) ]] No parties dispute the facts that: ( 1) NOx emissions from EGUs are a strong function of fuel type and ( 2) the relative mix of EGU firing by coal, oil and gas varies significantly among the CAIR states. Furthermore, the application of highly cost effective controls to a coal fired EGU will consistently result in a NOx emission rate higher than the comparable rate obtained by applying those controls to either a gas fired or an oil fired unit. Therefore, the application of highly cost effective controls to NOx emissions from each state= s EGUs realistically cannot result in each state= s controlled NOx emission rate being identical because the amounts of EGU NOx emissions from ( 1) coal, ( 2) oil and ( 3) gas each vary appreciably among the states. [[ ( 2271.1, p. 6) ]] Indeed, from NOx emission data for each fuel type recently burned in the CAIR region= s EGUs, EPA determined that the NOx emission rate from those EGUs firing gas was only 40% of the NOx emission rate from the region= s coal fired units. Similarly, the Agency found that the NOx emission rate from the region= s oil fired EGUs was only 60% of that emission rate from the EGUs firing coal. Therefore, to account for this inherent NOx emission variability as a function of fuel type, EPA multiplied each state= s annual heat input from each fuel type by a > fuel factor= for that fuel type ( 1.0 for coal, 0.6 for oil and 0.4 for gas) to obtain an > adjusted heat input= for that fuel type. [[ ( 2271.1, p. 6) ]]

In this fashion, EPA accounted for the fact that some states have a greater percentage of coal units in their generation mixes than others. The only justification for calculating state NOx budgets using a uniform NOx emission rate, as Entergy urges, would be if every state had the same mix of fossil resources. But they don= t. [[ ( 2271.1, p. 6) ]] It is true, as Entergy says, that use of fuel adjustment factors increases NOx budgets for the more coal fired states at the expense of the more gas fired states as compared with the NOPR allocation methodology. But this is reflective of the fact that the NOPR allocation method failed to account for the different generation mixes and therefore different NOx emission rates in each state.

If one performed a state by state analysis of the emission reductions each state would make through application of highly cost effective controls, there is no question that states with a greater proportion of gas fired units would be subject to less extensive control requirements than states with a greater proportion of coal fired units. Gas fired plants emit much less NOx than coal fired plants, and the cost of control at gas fired plants is much higher than at coal fired plants. Thus, EPA= s use of fuel adjustment factors does no more than reflect the fact that states with the higher amounts of coal power in their generating mixes are, as compared with states with higher amounts of gas power, ( a) greater NOx emitters, ( b) would be required to control more through the application of highly cost effective controls, and ( c) therefore are assigned higher budgets. [[ ( 2271.1, p. 7) ]] As EPA found, although states such as Louisiana will indeed receive a lower NOx budget than they would under the NOPR methodology, in general Louisiana and the other gas fired states will receive sufficient allowances to continue operations without having to purchase allowances. States that are not primarily coal fired should not be assigned budgets as if they were, and as if they were going to have emission reduction costs that they will not in fact bear. [[ ( 2271.1, p. 7) ]] As a reasonable response to Section 110( a)( 2)( D), EPA= s methodology will be entitled to judicial deference. Section 110( a)( 2)( D) prohibits any state= s emissions from contributing significantly to another state= s nonattainment. The statute is silent on the meaning of the term > significant contribution.= In Michigan v. EPA, 213 F. 3d 663, 678 ( D. C. Cir. 2000), the Court found this phrase was ambiguous. The Court upheld as permissible EPA= s interpretation of that term as the quantity of out of state contribution that would be eliminated if a state= s emissions were reduced by an amount achievable using > highly cost effective= controls on EGUs in that state. Id. At 678 79. [[ ( 2271.1, p. 8) ]] Because the statute is silent on how EPA must interpret the term " significant contribution" a reviewing court will ask whether EPA= s interpretation is based on a permissible construction of the statute. EPA must demonstrate a reasonable connection between the facts on the record and its decision made pursuant to its statutory authority. [[ ( 2271.1, p. 8) ]]

The facts in this case overwhelmingly confirm the reasonableness of EPA= s decision to use fuel factors in determining state NOx budgets. As noted, the initial methodology considered by EPA in the CAIR NOPR for setting State NOx budgets required all states to have the same NOx emission rate after application of controls to eliminate each state= s significant contribution. That result plainly does not accurately depict, or even approximate, what the result would be in each state if each was required to install highly cost effective controls. As such, that approach provides no assurance that each state= s significant contribution to downwind nonattainment will actually be eliminated. [[ ( 2271.1, pp. 8 9) ]] By contrast, the alternate methodology, using fuel factors to account for variations in NOx emissions as a function of fuel type, provides a realistic approximation of the NOx emissions actually remaining in each state after application of highly cost effective controls to EGUs. In doing so, that methodology provides confidence that it will result in eliminating each state= s significant contribution. [[ ( 2271.1, p. 9) ]] EPA= s use of fuel factors to more accurately quantify remaining NOx emissions in each state, thereby providing greater assurance that the State= s significant contribution is eliminated, is clearly a reasonable decision and one that will therefore be entitled to judicial deference.

After all, the better a regulatory provision satisfies its statutory objective, the more rational that agency decision is. [[ ( 2271.1, p. 9) ]] Entergy misinterprets the Michigan case by claiming the Court endorsed the CAIR NOPR methodology, which was the same methodology used in the NOX SIP Call, as the only one allowable under Section 110( a)( 2)( D). To the contrary, the Michigan Court found that EPA= s interpretation of Section 110( a)( 2)( D) was permissible, not exclusive. As shown above, the methodology used in the final CAIR improves on the methodology proposed in the NOPR by providing a better approximation of what a state= s actual significant contribution to downwind nonattainment may be. For that reason, the final CAIR methodology is also a permissible interpretation of the statute. [[ ( 2271.1, p. 9) ]] Entergy also argues that use of the fuel adjustment factors contradicts EPA= s own determination that the amount of each state= s emissions reductions should reflect the use of> highly cost effective controls on EGUs. Relying on statements in the NOPR preamble, Entergy maintains that EPA has previously determined that highly cost effective controls on EGUs were those that could achieve an emission rate of 0.15 lb/ mmBtu by 2009 and 0.125 lb/ mmBtu by 2015. [[ ( 2271.1, pp. 9 10) ]] Again, Entergy misapprehends EPA= s underlying methodology. EPA applied highly costeffective controls to EGUs throughout the region and determined a region wide average emission rate ( and therefore determined the regional significant contribution to downwind nonattainment). EPA never determined that this region wide average emission rate necessarily reflects the emission rate that would result in a particular state through the application of highly costeffective controls in that state. As shown above, such a conclusion would not be correct. As seen, the states within the CAIR region have different mixes of generation and therefore logically should not have their budgets calculated using the same NOX rate per MMBtu. It is, therefore, entirely rational for EPA, having computed a region wide average NOX rate per MMBtu, to utilize fuel adjustment factors to ensure that an individual state= s budget reflects that state= s individual fuel mix, control costs, and significant contribution to downwind nonattainment. [[ ( 2271.1, p. 10) ]] It is true the simple heat input methodology proposed in the NOPR preamble would have resulted in all of the CAIR region states having the identical NOX emissions rates after application of CAIR controls. But EPA is certainly not precluded from developing a modified methodology in the final rule as a result of comments, one that more accurately reflects individual states= significant contribution to downwind nonattainment. After all, obtaining the best result is the purpose of notice and comment rulemaking. [[ ( 2271.1, pp. 10 11) ]]

Response: The commenter generally supports use of the FAF methodology, the approach taken in the CAIR and CAIR FIP.

Document No.: OAR 2003 0053 2283.1 Commenter: Entergy Corporation Comment: Entergy owns and operates power plants that are directly affected by CAIR and the fuel adjustment. Entergy is an integrated energy company engaged primarily in electric power production, transmission, retail distribution operations, energy marketing and trading, and gas transportation. Entergy owns and operates power plants with approximately 30,000 megawatts of electric generating capacity and is the second largest nuclear generator in the United States. Through power plants located in Louisiana, Mississippi, Texas, and Arkansas, Entergy delivers electricity to 2.6 million utility customers in those States. Each of these states is regulated under CAIR and the annual NOx budgets for Louisiana, Mississippi and Texas ( Arkansas is not subject to annual NOx reductions) were significantly reduced by the fuel adjustment. [[ docket number 2283.1, p. 1]]

Entergy strenuously objects to the use of the fuel adjustment in setting the states= annual and ozone season NOx budgets under CAIR. Entergy urges EPA to revise CAIR so that the state= s NOx budgets are those set forth in the Final Rule without the application of the fuel adjustment. Entergy= s comments are provided below. [[ docket number 2283.1, p. 1]]

The Fuel Adjustment Significantly Redistributed the States= NOx Budgets from the Periphery to the Center of the CAIR Region.[[ docket number 2283.1, p. 1]] [[ See docket number 2283.1, pp. 1 2 for further discussion of this issue. Also see Attachments 1 3 at docket number 2283.1, pp. 16 18.]]]] V. EPA= s Claim that the Budgets of States Disadvantaged by the Fuel Adjustment are Sufficient to Cover Their Future Emissions Belies any Justification for Including These States in CAIR. EPAs claim that the fuel adjustment does no harm to states with significant gas and oil generation contradicts the very rationale for requiring these States to make NOx reductions under CAIR in the first place. This contradiction reveals the arbitrariness of the fuel adjustment EPA attempts to justify. [[ docket number 2283.1, p. 6]] [[ See docket number 2283.1, pp. 6 8 for discussion of this issue.]] VI. The Fuel Adjustment Contradicts EPA= s Own Determination that Each State= s Reduction is Based on Highly Cost Effective Controls. [ docket number 2283.1, p. 8]] [[ See docket number 2283.1, pp. 8 9 for discussion of this issue.]] VII.

The Clean Air Act Does Not Authorize EPA to Base a State= s Budget on Factors Wholly Unrelated to Air Quality. [[ docket number 2283.1, p. 9]] See docket number 2283.1, pp. 9 12 for discussion of this issue.]] VIII. EPA= s Claim that the Fuel Adjustment will not Materially Affect the Magnitude and Location of Emission Reductions Is Erroneous. [ Docket number 2283.1, p. 12]] [[ See docket number 2283.1, pp. 12 14 for discussion of this issue. Also see Attachments 4 and 5 at docket number 2283.1, pp. 19 and 20.]] IX. EPA= s Failure to Re run the Air Quality Models to Assess the Effects of the Changes in Emission Reductions Resulting from the Fuel Adjustment is Arbitrary. [ docket number 2283.1, p. 14]] [[ See docket number 2283.1, pp. 14 15 for discussion of this issue.]]

The Fuel adjustment inappropriately rewards higher emitting coal generation and penalizes prior investments in lower emitting gas and oil generation. [[ docket number 2281.1, p. 2]] [[ See docket number 2283.1, pp. 2 4 for further discussion of this issue.]] III. EPA= s Assumption that Coal Fired Units Will Bear the Burden of Emission Reductions under CAIR is Wrong. [[ docket number 2283.1, p. 4]] See docket number 2283.1, pp. 4 5 for discussion of this issue.]] IV. EPA= s Assumptions about the Early Retirement of Gas and Oil Units are Erroneous. [[ docket number 2283.1, p. 5]] See docket number 2283.1, pp. 5 6 for discussion of this issue.]]

Response:

EPA disagrees with the commenters claim that the use of a FAF approach effectively increases the levels of emission reductions mandated for Louisiana ( or any of the CAIR States). Because CAIR uses a regionwide cap and trade approach, it is possible for sources in any State to purchase emission allowances on the market   effectively finding least cost reductions no matter where in the CAIR region the controlling source is located. This is independent of the original distribution of allowances. EPA's position is based upon experience with the highly successful Acid Rain Program, the NOx SIP Call program, and extensive modeling that the Agency, the Energy Information Administration, and other groups have done with optimization models designed to consider this issue. The commenter provided no analysis to support their claim. In addition, EPA analysis presented in the Notice of Reconsideration demonstrates that the States with predominantly non coal generation will have an excess of allowances under either the FAF or simple heat input approaches.

Similarly, EPA also disagrees with the commenter that the use of a FAF approach " contradicts EPA's own decision to base emission reductions on the use of highly cost effective controls." EPA determined that " highly cost effective reductions" were available from the power sector in the entire CAIR region. This regionwide determination was independent of any particular method of apportioning the regionwide emission cap to the States. As a result, the commenters' contention that EPA must conduct a new cost effectiveness determination using the FAF approach statewide budgets is not justified. As mentioned above, determination of emissions reductions that are highly cost effective depends on the cost of pollution controls that are used to minimize compliance costs, not the distribution of allowances to any one source or State within the CAIR region where emission reductions that free up allowances that can be sold to other electric generation units covered by the program. Additionally, under a regionwide cap andtrade approach, the market approach allows sources to find the least cost reductions. Furthermore, EPA chose to implement the FAF methodology because it generally reduced the disparity between the projected statewide emissions under CAIR and the allowance budgets of the States.

The commenter claims that use of the FAF approach would shift the " burden of emission reductions" to the " outer edges of the CAIR region." Some limited analysis to support this claim was provided by the commenter. However, EPA disagrees with the commenter's claim the use of the FAF approach leads to " shifting  emissions  closer to the affected downwind nonattainment areas intended to benefit from CAIR." EPA analysis has shown that using either the simple heat input or the FAF methodologies, the CAIR results in the same emission reductions taking place at the same sources. Use of the FAF approach simply shifts who pays and how much they pay for emission reductions, as well as the amount some States with lower emission rates already might stand to make without doing anything to benefit the environment. As stated earlier, EPA modeling shows that States with predominantly coal fired generation ( i. e., those States that receive slightly more allowances under a FAF approach) are projected to make larger investments in emission controls under CAIR. The commenter did not provide analysis to demonstrate that emissions would increase in States that are closer to affected downwind nonattainment areas.