With respect to setting the upper bound of potential highly cost effective controls, EPA determined this level on the basis of average cost effectiveness ( the average cost per ton of pollutant removed). The EPA explained that it relied on average cost effectiveness for two reasons:

Since EPA's determination for the core group of sources is based on the adoption of a broad based trading program, average cost effectiveness serves as an adequate measure across sources because sources with high marginal costs will be able to take advantage of this program to lower their costs. In addition,

average cost effectiveness estimates are readily available for other recently adopted NOx control measures ( 63 FR 57399).

At that time, EPA acknowledged that average cost effectiveness did not directly address the fact that certain units might have higher costs relative to the average cost of reduction ( e. g., units with lower capacity factors tend to have higher costs):

[ I] ncremental cost effectiveness helps to identify whether a more stringent control option imposes much higher costs relative to the average cost per ton for 200 further control. The use of an average cost effectiveness measure may not fully reveal costly incremental requirements where control options achieve large reductions in emissions ( relative to the baseline) ( 63 FR 57399).

Examination of marginal cost effectiveness   which examines what the cost would be of the next ton of reduction after the defined control level   would fill this gap.

However, for the NOx SIP Call rulemaking, adequate information concerning marginal cost effectiveness was not available.

For the NOx SIP Call, to determine the average cost effectiveness that should be considered to be highly cost effective, EPA developed a " reference list" of NOx emissions controls that are available and of comparable cost to other recently undertaken or planned NOx measures. The EPA explained that " the cost effectiveness of measures that EPA or States have adopted, or proposed to adopt, forms a good reference point for determining which of the available additional NOx control measures can most easily be implemented by upwind States whose emissions impact downwind nonattainment problems." ( 63 FR 57400). The EPA explained 201 that the measures on the reference list had already been implemented or were planned to be implemented, and therefore could be assumed to be less expensive than other measures to be implemented in the future. The EPA found that the costs of the measures on the reference list approached but were below $ 2,000 per ton ( 1990$). The EPA concluded that " controls with an average cost effectiveness [ of] less than $ 2,000 [ 1990$, or $ 2,500 ( 1999$)] per ton of NOx removed [ should be considered] to be highly cost effective." ( 63 FR 57400). Notably, the reference costs were taken from the supporting analyses used for the regulatory actions covering the NOx pollution controls   they are what regulatory decision makers and the public believed were the control costs.

Mindful of this $ 2,000 limit [ 1990$, or $ 2,500 ( 1999$)], EPA considered a control level that would have resulted in estimated average costs of approximately $ 1,800 ( 1990$) per ton. However, EPA concluded that because the corresponding level of controls   nominally a 0.12 lb/ mmBtu control level   was not well enough established, EPA was " not as confident about the robustness" of the cost estimates. Moreover, EPA expressed concern that its " level of comfort" was not as high as it would have liked that the nominal 0.12 lb/ mmBtu control level " will not lead to 202 installation of SCR technology at a level and in a manner that will be difficult to implement or result in reliability problems for electric power generation" ( 63 FR 57401).

Accordingly, EPA selected the next control level that it had evaluated   a nominal 0.15 lb/ mmBtu level   which would result in an average cost of approximately $ 1,500 [ 1990$, or $ 1,900 ( 1999$)] per ton. The EPA determined that this control level did not present the uncertainty concerns associated with the 0.12 level. The EPA added, in this 1998 rule: " With a strong need to implement a program by 2003 that is recognized by the States as practical, necessary,

and broadly accepted as highly cost effective, the Agency has decided to base the emissions budgets for EGUs on a 0.15 ... level." ( 63 FR 57401  57402). The EPA summarized its approach as determining " the required emission levels ...

based on the application of NOx controls that achieve the greatest feasible emissions reduction while still falling within a cost per ton reduced range that EPA considers to be highly cost effective...." ( 63 FR 57399).

The bulk of the cost for reducing NOx emissions for EGUs is in the capital investment in the control equipment,

which would be the same whether controls are installed for ozone season only, or for annual controls. The increased costs to run the equipment annually instead of only in the 203 ozone season is relatively small. Although the NOx SIP Call is an ozone season NOx reduction program, most of the NOx control costs on the reference list are for annual reductions. If the NOx SIP Call were an annual program instead of seasonal, its average control costs would be lower, relative to the annual control costs in the reference list.

ii. Other Factors In the NOx SIP Call, although considering air quality and cost to be the primary factors for determining significant contribution, EPA identified several other factors that it generally considered. As one factor, EPA reviewed " overall considerations of fairness related to the control regimes required of the downwind and upwind areas,"

particularly, the fact that the major urban nonattainment areas in the East had implemented controls on virtually all portions of their inventory of ozone precursors, but upwind sources had not implemented reductions intended to reduce their impacts downwind ( 63 FR 57404).

As another factor, EPA generally considered " the cost effectiveness of additional local reductions in the ...

ozone nonattainment areas." The EPA included in the record information that nationally, on average, additional local measures would cost more than the cost of the upwind 204 controls required under the NOx SIP Call. This consideration further indicated that the regional controls under the NOx SIP Call were highly cost effective ( 63 FR 57404).

In addition, EPA conducted air quality modeling to determine the impact of the controls, and found that they benefitted the downwind areas without being more than necessary for those areas to attain ( 63 FR 57403  57404).

c. Proposed Criteria for Emissions Reduction Requirements i. General Criteria In the CAIR NPR, EPA proposed criteria for determining the appropriate levels of annual emissions reductions for SO2 and NOx and ozone season emissions reductions for NOx.

The EPA stated that it considers a variety of factors in evaluating the source categories from which highly cost effective reductions may be available and the level of reduction assumed from that sector. These include:

 the availability of information,

 the identification of source categories emitting relatively large amounts of the relevant emissions,

 the performance and applicability of control measures,

 the cost effectiveness of control measures, and  engineering and financial factors that affect the availability of control measures ( 69 FR 4611). 205 53 U. S. Environmental Protection Agency, Office of Air and Radiation, EPA's Clean Air Power Initiative, October 1996. Further, EPA stated that overall, " We are striving ...

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." ( 69 FR 4612)

The EPA has used these types of criteria in a number of efforts to develop regional and national strategies to reduce interstate transport of SO2 and NOx. Starting in 1996, EPA performed analysis and engaged in dialogue with power companies, States, environmental groups and other interested groups in the Clean Air Power Initiative ( CAPI). 53 In that study of national emission reduction strategies, EPA initially considered an emissions cap based on a 50 percent reduction in SO2 emissions from title IV levels ( i. e., 4.5 million tons nationwide) in 2010. For NOx, EPA initially looked at ozone season and non ozone season caps. Commencing in 2000, the ozone season emissions cap would be based on an emission rate of 0.20 lb/ mmBtu, and in 2005, the ozone season cap would be reduced to a level based on 0.15 lb/ mmBtu ( these cap levels would be similar to the phased caps adopted by the Ozone Transport Commission ( OTC) States). The non ozone season cap would be based on 206 54 U. S. Environmental Protection Agency, Office of Air and Radiation, Analysis of Emission Reduction Options for the Electric Power Industry, March 1999.

55 EPA's Clear Skies Act analysis is on the web at: www. epa. gov/ air/ clearskies/ technical. html. the proposed title IV phase II NOx rule. The EPA also considered other options in the CAPI study, including setting NOx caps based on emission rates of 0.20 lb/ mmBtu and 0.25 lb/ mmBtu; setting NOx caps based on rates of 0.15 lb/ mmBtu and 0.20 lb/ mmBtu but lowering the SO2 allowance cap by 60 percent instead of 50 percent; and, keeping a NOx cap based on a rate of 0.15 lb/ mmBtu but lowering the SO2 allowance cap by 50 percent in 2005 instead of in 2010.

The EPA did a follow up study in 1999 and discussed those results with various stakeholder groups, as well. 54 That study considered a variety of SO2 emission caps ranging from a 40 percent reduction from title IV cap levels in 2010 to a 55 percent reduction from title IV cap levels in 2010.

The 1999 study did not consider additional reductions in NOx emissions beyond those required under the NOx SIP Call.

In the last several years, EPA has performed significant additional analysis in support of the proposed Clear Skies Act. 55 That legislation, proposed in 2002 and 2003, would include nationwide SO2 caps of 4.5 million tons in 2010 and 3.0 million tons in 2018 ( i. e., 50 percent and 67 percent reductions from title IV cap levels). The Clear 207 Skies Act also includes a two phase, two zone NOx emission cap program, with the first phase in 2008 and the second phase in 2018. In the 2003 legislation, the first phase NOx caps would result in effective NOx emissions rates of 0.16 lb/ mmBtu in the east and 0.20 lb/ mmBtu in the west, and the second phase would result in effective emission rates of 0.12 lb/ mmBtu in the east and 0.20 lb/ mmBtu in the west.

ii. Reliance on Average and Marginal Cost Effectiveness In the CAIR NPR, EPA supported the conclusion that its emissions caps are highly cost effective based upon "( 1)

comparison to the average cost effectiveness of other regulatory actions and ( 2) comparison to the marginal cost effectiveness of other regulatory actions." ( 69 FR 4585).

We supplemented these comparisons of cost effectiveness tables with an auxiliary evaluation of the marginal costs curves, which allowed us to show that the selected control levels would be " below the point at which there would be significant diminishing returns on the dollars spent for pollution control." ( 69 FR 4614).

Although in the NOx SIP Call, EPA based the required controls on average cost alone, in today's rule, EPA uses both average and marginal costs, including an evaluation of the marginal cost curves. At the time of the NOx SIP Call,

marginal cost information was not as readily available. 208 Today, such information is available for both SO2 and NOx controls, although marginal cost information remains more limited and EPA has had to specifically develop marginal cost estimates for use in this rulemaking.

Marginal costs are a useful measure of cost effectiveness because they indicate how much any additional level of control at the margin will cost relative to other actions that are available. Using both average and marginal control costs, provides a more complete picture of the costs of controls than using average costs alone. Average costs provide a means for a straightforward comparison between the CAIR and other emissions reductions programs for which average costs are generally the only type of costs available. Where marginal cost information is available, it enables EPA to compare the costs of the CAIR at the stringency level being considered to the costs of the last increment of control in other programs. Moreover,

evaluation of marginal cost curves allows us to corroborate that the selected level of stringency of the selected program stops short of the point where the returns begin to diminish significantly.

Projected marginal cost information for controlling emissions from EGUs is now available for some State programs, because EPA includes the programs in its base case 209 power sector modeling using the IPM to develop the incremental costs of electricity production for the CAIR.

Marginal EGU control costs from State programs modeled using the IPM were compared to projected marginal EGU control costs under the CAIR, as discussed in more detail below.

3. What Are the Most Significant Comments that EPA Received about its Proposed Methodology for Determining the Amounts of SO2 and NOx Emissions that Must Be Eliminated,

and What Are EPA's Responses?

Some commenters took issue with EPA's reliance on cost per ton of emissions reductions as the metric for determining cost effectiveness. These commenters observed that this metric does not take into account that any given ton of pollutant reduction may have different impacts on ambient concentration and human exposure. Some of these commenters advocated use of a metric based on cost per unit of pollutant concentration reduced. Another stated that EPA should account for cost effectiveness based on geographical location relative to the area of nonattainment.

Still other commenters took a contrasting view. They argued that a metric based on cost per ambient impact might be useful in justifying control cost effectiveness for source categories within an individual nonattainment area as part of an attainment SIP, but not for evaluating costs of controlling long range transport. These commenters stated that it is impractical to calculate cost effectiveness of 210 control on the basis of cost per unit reduction in ambient concentration. One queried: " Where would the ambient reduction be measured? 100 miles downwind? 1,500 miles downwind?"

The EPA agrees that optimally, the cost per ambient impact of controls could play a major role in determining upwind control obligations ( although equitable considerations and other factors identified in the NOx SIP Call rulemaking and today's action may also play a role). The EPA recognized the potential importance of this factor during the NOx SIP Call rulemaking and endeavored to develop technical information to support it. However, in that rulemaking, EPA was not able to develop an approach to quantify, with sufficient accuracy, cost per ambient impact because the NOx SIP Call region was large B covering approximately half of the continental U. S. and including approximately half the States B and many upwind States with different emissions inventories had widely varied impacts on many different nonattainment areas downwind.

This problem B the complexity of the task and the dearth of analytic tools B remains today for both PM2.5 and 8 hour ozone regional transport. Not surprisingly, no commenter presented to EPA the analytic tools, which we would expect would consist of a complex, computerized program that could integrate, on a State by State basis,

both control costs and ambient impacts by each State on each 211 of its downwind receptors under the CAIR control scenario.

In the absence of a scientifically defensible,

practicable method for implementing a program design approach based on the cost per ambient impact of emissions reductions, EPA is not able to employ such an approach.

However, EPA believes it appropriate to continue to examine ways to develop such an approach for future use.

A few commenters suggested that EPA should use a cost benefit analysis for determining reduction levels. One noted that cost benefit analysis can help find the reduction levels that maximize societal net benefit ( benefits minus costs), and suggested the Agency should compare the marginal cost of each ton of pollutant reduced to the marginal benefit achieved, as well as compare the total costs to the total benefits. Another stated that an optimal allocation of resources is where the marginal cost equals the marginal benefit, and observed that comparing the average cost to the average benefit of the controls proposed in the CAIR NPR yields an average benefit significantly higher than the average cost. This commenter concluded that EPA should require controls beyond the controls described in the NPR as highly cost effective.

Although EPA strongly agrees that examination of costs and benefits is very useful, in today's rulemaking, EPA does not interpret CAA section 110( a)( 2)( D) to base the amount of 212 emissions reductions on benefits other than progress towards attainment of the PM2.5 or the 8 hour ozone NAAQS. The EPA's interpretation does, however, use cost effectiveness per ton of pollutant reduced, and we are using that analytic tool for setting SO2 and NOx emission reduction requirements. Additionally, EPA has prepared a cost benefit analysis to inform the Agency and public of the many other important impacts of this rulemaking.

A few commenters suggested that the Agency should set its NOx and SO2 reduction requirements based on Best Available Control Technology ( BACT) emission rates for EGUs.

Although not clearly stated, the commenters appear to suggest BACT level controls for both existing and new units.

The emission reduction requirements that EPA determined are based on the application of highly cost effective controls that are a step that the Agency is taking at this time to eliminate emissions that contribute significantly to nonattainment of the ozone and fine particle NAAQS. As explained elsewhere, this step is reasonable in light of the current status of implementation for those NAAQS.

Basing emission reduction requirements on a presumption of BACT emission rates across the board would require scrubbers and SCRs on all coal fired units and SCRs on all gas fired and oil fired units. The cost of these 213 controls would vary considerably from source to source, be expensive for many sources, and may cause substantial fuel switching to natural gas and closure of smaller coal fired units. Having considered this suggestion for deeper regional reductions that would not be as cost effective as the highly cost effective reductions in today's rule, EPA believes that a more tailored approach, such as the CAIR level control as well as local controls under SIPs ( where necessary), is a more reasonable approach to achieving the level of ambient improvement needed for attainment throughout the United States.

4. EPA's Evaluation of Highly Cost Effective SO2 and NOx Emissions Reductions Based on Controlling EGUs a. SO2 Emissions Reductions Requirements i. CAIR Proposal for SO2 The NPR focused primarily on determining highly costeffective amounts of emissions reductions based on, as in the NOx SIP Call, comparison to reference lists of the cost effectiveness of other regulatory controls. In the NPR, EPA developed reference lists for both the average cost effectiveness and the marginal cost effectiveness of those other controls. These reference lists indicated that the average annual costs per ton of SO2 removed ranged from $ 500 to $ 2,100; and marginal costs of SO2 removal ranged from 214 $ 800 to $ 2,200.

Moreover, EPA further considered the cost effectiveness of alternative stringency levels for this regulatory proposal. That is, EPA examined changes in the marginal cost curve at varying levels of emissions reductions. The EPA determined in the NPR that the " knee" in the marginal cost effectiveness curve  the point at which the marginal cost per ton of SO2 removed begins to increase at a noticeably higher rate   appears to start above $ 1,200 per ton ( 69 FR 4613  4615).

In the NPR, EPA then provided further analysis of a two phase SO2 reduction program. The final ( second) phase,

in 2015, would reduce SO2 emissions in the CAIR region by the amount that results from making a 65 percent reduction from the title IV Phase II allowance levels ( taking into consideration the existing bank of title IV SO2 allowances).

The first phase, in 2010, would reduce SO2 emissions in the CAIR region by a lesser amount, i. e., a 50 percent reduction from title IV Phase II allowance levels ( again, taking into consideration the banked title IV SO2 allowances). The EPA developed this target SO2 control level for further evaluation because, based on all of the earlier work performed on multi pollutant power plant reduction programs and general consideration, with technical support, of 215 overall emissions reductions, costs to industry and the general public, ambient improvement, and consistency with the emerging PM2.5 implementation program, we believed it would meet the criteria set forth above.

Then, EPA conducted cost analyses of this control level using the IPM as well as additional analysis of the implications of this control level to determine if it did indeed meet those criteria. The IPM analysis considered the increase in annual electric generation production costs in the CAIR region that result from the rule. The EPA evaluated the cost effectiveness of the final phase ( 2015)

cap to determine if it is highly cost effective; and, we also evaluated the cost effectiveness of the 2010 cap. The EPA used the IPM to estimate cost effectiveness of the CAIR in the future. The IPM incorporates projections of future electricity demand, and thus heat input growth. The EPA's IPM analyses for the CAIR includes all fossil fuel fired EGUs with capacity greater than 25 MW. A description of the IPM is included elsewhere in this preamble, and a detailed model documentation is in the docket.

The SO2 annual control costs that were presented in the CAIR NPR were average costs of $ 700 per ton and $ 800 per ton for years 2010 and 2015, respectively, and marginal costs of $ 700 per ton and $ 1,000 per ton for years 2010 and 2015. In 216 addition, the NPR included the results of sensitivity analyses that examined costs of the proposed SO2 controls based on the Energy Information Administration's projections for electricity growth and natural gas prices. These sensitivity analyses showed marginal SO2 control costs of $ 900 per ton and $ 1,100 per ton for years 2010 and 2015,

respectively. The EPA proposed to consider the SO2 emissions reductions proposed in the NPR as highly cost effective because they were consistent with the lower end of the reference list range of cost per ton of SO2 reduction for controls on both an average and a marginal cost basis ( 69 FR 4613  4615).

ii. Analysis of SO2 Emission Reduction Requirements for Today's Final Rule ( I) Reference Lists of Cost Effective SO2 Controls For today's action, EPA updated the reference list of controls included in the NPR of the average and marginal costs per ton of recent SO2 control actions. The EPA systematically developed a list of cost information from both recent actions and proposed actions. The EPA compiled cost information for actions taken by the Agency, and examined the public comments submitted after the NPR was published, to identify all available control cost information to provide the updated reference list for 217 6 The updated reference list includes estimated average costs for SO2 reductions from EGUs under best available retrofit technology ( BART) requirements. The BART rule was proposed and has not been finalized ( 69 FR 25184; May 5, 2004). today's preamble. The updated reference list includes both average and marginal costs of control, to which EPA compares the CAIR control costs, and the list represents what regulatory decision makers and/ or the public believes are the control costs. 56 Table IV 3 provides average costs of SO2 controls.

This table includes average costs for recent BACT permitting decisions for SO2. Under EPA's New Source Review ( NSR)

program, if a company is planning to build a new plant or modify an existing plant such that a significant net increase in emissions will occur, the company must obtain a NSR permit that addresses controls for air emissions. BACT is the type of control required by the NSR program for existing sources in attainment areas. The BACT decisions are determined on a case by case basis, usually by State or local permitting agencies, and reflect consideration of average and incremental cost effectiveness. These decisions are relevant for EPA's reference list of average costs of SO2 controls, because they represent cost effective controls that have been demonstrated.

Table IV 3. Average Costs per Ton of Annual SO2 Controls 218 SO 2 Control Action Average Cost per Ton Best Available Control Technology ( BACT) Determinations $ 400 B $ 2,100 1 Nonroad Diesel Engines and Fuel $ 800 2 Proposed Best Available Retrofit Technology ( BART) for Electric Power Sector $ 2,600  $ 3,400 3 1 These numbers reflect a range of cost effectiveness data entered into EPA's RACT/ BACT/ LAER Clearinghouse ( RBLC) for add on SO2 controls ( www. epa. gov/ ttn/ catc/). We identified actions in the data base for large, utility scale, coal fired boiler units for which cost effectiveness data were reported. The range of costs shown here is for boilers ranging from 30 MW to an estimated 790 MW ( we used a conversion factor of 10 mmBtu/ hr = 1 MW for units for which size was reported in mmBtu/ hr). Emission limits for these actions ranged from 0.10 lb/ mmBtu to 0.27 lb/ mmBtu. Add on controls reported for these units are dry or wet scrubbers ( in one case with added alkali and in one case with a baghouse). Where the dollar year was not reported we assumed 1999 dollars. The cost range presented in the NPR was $ 500  $ 2,100 B today's range includes additional BACT costs that were entered into the clearinghouse after the NPR was published. 2 Control of Emissions of Air Pollution From Nonroad Diesel Engines and Fuel; Final Rule ( 69 FR 39131; June 29, 2004). The value in this table represents the long term cost per ton of emissions reduced from the total fuel and engine program ( cost per ton of emissions reduced in the year 2030). 1999$ per ton. 3 The EPA IPM modeling 2004, available in the docket. The EPA modeled the Regional Haze Requirements as source specific limits ( 90 percent SO2 reduction or 0.1 lb/ mmBtu rate; except the five state WRAP region for which we did not model SO2 controls beyond what is done for the WRAP cap in the base case modeling). Estimated average costs based on this modeling are $ 2,600 per ton in 2015 and $ 3,400 per ton in 2020. 1999$ per ton.

Table IV 4 provides the marginal cost per ton of recent State and regional decisions for annual SO2 controls.

Table IV 4. Marginal Costs per Ton of Annual SO2 Controls SO 2 Control Action Marginal Cost per Ton New Hampshire Rule $ 600 1 WRAP Regional SO 2 Trading Program $ 1,100 B $ 2,200 2 1 The EPA IPM Base Case modeling August 2004, available in the docket. ( 1999$ per ton). We modeled New Hampshire's State Bill ENV A2900, which caps SO2 emissions at all existing fossil steam units. 2 " An Assessment of Critical Mass for the Regional SO 2 Trading Program," prepared for Western Regional Air Partnership Market Trading Forum by ICF Consulting Group, September 27, 2002, available in the docket. This analysis looked at the implications of one or more States choosing to opt out of the WRAP regional SO 2 trading program. ( 1999$ per ton) 219 ( II) Cost Effectiveness of the CAIR Annual SO2 Reductions In the NPR, EPA evaluated an annual SO2 control strategy based on a specified level of emissions reductions from EGUs. Available information indicated that emissions reductions from this industry would be the most cost effective. ( As noted elsewhere, EPA considered control strategies for other source categories, but concluded that they would not qualify as highly cost effective controls.)

Of course, under today's rule, although EPA calculates the amount of emissions reductions States must achieve by evaluation of the EGU control strategy, States remain free to achieve those reductions by implementing controls on any sources they wish.

For today's action, EPA updated the predicted annual SO2 control costs included in the NPR. The EPA analyzed the costs of the CAIR using an updated version of the IPM ( documentation for the IPM update is in the docket).

Further, EPA modified the modeling to match the final CAIR strategy ( see section IV. A. 1 for a description of EPA's CAIR IPM modeling).

The EPA also updated its analysis of the sensitivity of the marginal cost results to assumptions of higher electric growth and natural gas prices than we used in the base case. These sensitivity analyses were based on the 220 7 The EPA used the difference between EIA's estimates for well head natural gas prices and minemouth coal prices to determine the sensitivity of IPM's results to higher natural gas prices. The EPA describes this sensitivity analysis as " EIA natural gas prices". For electric demand, we replaced EPA's assumed annual growth of 1.6 percent with EIA's projection of annual growth of 1.8 percent. Energy Information Administration's Annual Energy Outlook for 2004.57 In determining whether our control strategy is highly cost effective, EPA believes it is important to account for the variable levels of cost effectiveness that these sensitivity analyses indicate may occur if electricity demand or natural gas prices are appreciably higher than assumed in the IPM. Those two factors are key determinants of control costs and, over the relatively long implementation period provided under today's action, a meaningful degree of risk arises that these factors may well vary to the extent indicated by the sensitivity analyses.

As a result, EPA wanted to examine the marginal costs that would occur under the scenarios modeled in the sensitivity analyses to see how they differed from the costs using EPA's assumptions.

Table IV 5 provides the average and marginal costs of annual SO2 reductions under the CAIR for 2010 and 2015.

( When presenting estimated CAIR control costs in section IV of this preamble, EPA uses " Main Case" to indicate the 221 primary CAIR IPM analyses, as differentiated from other IPM analyses such as sensitivity runs used to examine the impacts of varying assumptions about natural gas price and electric growth.)

Table IV 5. Estimated Costs per Tons of SO2 Controlled Under CAIR, Cap Levels Beginning in 2010 and 2015 1 Type of Cost Effectiveness 2010 2015 Average Cost  Main Case $ 500 $ 700 Marginal Cost  Main Case $ 700 $ 1,000 Sensitivity Analysis: Marginal Cost Using EIA Electric Growth and Natural Gas Prices $ 800 $ 1,200 1 The EPA IPM modeling 2004, available in the docket. 1999$ per ton.

These estimated SO2 control costs under the CAIR reflect annual EGU SO2 caps of 3.6 million tons in 2010 and 2.5 million tons in 2015 within the CAIR region. Based on IPM modeling, EPA projects that SO2 emissions in the CAIR region will be about 5.1 million tons in 2010 and 4.0 million tons in 2015. The projected emissions are above the cap levels because of the use of the existing title IV bank of SO2 allowances. Average costs shown for 2015 are an estimate of the average cost per ton to achieve the total difference in projected emissions between the base case conditions and the CAIR in the year 2015 ( the 2015 average costs are not based on the increment in reductions between 2010 and 2015). ( A more detailed description of the final 222 CAIR SO2 and NOx control requirements is provided below in today's preamble.)

( III) SO2 Cost Comparison for CAIR Requirements The EPA believes that if an SO2 control strategy has a cost effectiveness that is at the low end of the updated reference tables, the approach should be considered to be highly cost effective. The costs in the reference range should be considered to be cost effective because they represent actions that have already been taken to reduce emissions. In deciding to require these actions,

policymakers at the local, State and Federal levels have determined them to be cost effective reductions to limit or reduce emissions. Thus, costs at the bottom of the range must necessarily be considered highly cost effective.

Today's action requires SO2 emissions reductions ( or an EGU emissions cap) in 2015. The EPA has determined that those emissions reductions are highly cost effective. In addition, today's action requires that some of those SO2 emissions reductions ( or a higher EGU emissions cap) be implemented by 2010. The EPA has examined the cost effectiveness of implementing those earlier emissions reductions ( or cap) by 2010, and determined that they are also highly cost effective.

The cost of the SO2 reductions required under today's 223 8 The updated reference list of average SO2 control costs includes estimated average EGU costs under BART. The BART rule has been proposed but not finalized ( 69 FR 25184; May 5, 2004). action   if the States choose to implement those reductions through EGUs, for which the most cost effective reductions are available   on average and at the margin, are at the lower end of the range of cost effectiveness of other,

recent SO2 control requirements. 58 This is true for our analysis of both the costs EPA generally expects as well as the somewhat higher costs that would result from higher than expected electricity demand and natural gas prices, as indicated in the sensitivity analyses that EPA has done.

Specifically, the average cost effectiveness of the SO2 requirements is $ 700 per ton removed in 2015. This amount falls toward the low end of the reference range of average costs per ton removed of $ 400 to $ 3,400. Similarly, the marginal cost effectiveness of the SO2 requirements ranges from $ 1,000 to $ 1,200 for 2015 ( with the higher end of the range based on the sensitivity analyses). These amounts fall toward the lower end of the reference range of marginal cost per ton removed of $ 600 to $ 2,200.

The EPA believes that selecting as highly cost effective amounts toward the lower end of our average and marginal cost ranges for SO2 and NOx control is appropriate because today's rulemaking is an early step in 224 the process of addressing PM2.5 and 8 hour ozone nonattainment and maintenance requirements. The CAA requires States to submit section 110( a)( 2)( D) plans to address interstate transport, and overall attainment plans to ensure the NAAQS are met in local areas. By taking the early step of finalizing the CAIR, we are requiring a very substantial air emission reduction that addresses interstate transport of PM2.5 as well as a further reduction in interstate transport of ozone beyond that required by the NOx SIP Call Rule. Much of the air quality improvement resulting from reduced transport is likely to occur through broad and deep emissions reductions from the electric power sector, which has been a major part of the transport problem. Other air quality benefits will occur as the result of Federal mobile source regulations for new sources,

which cover passenger vehicles and light trucks, heavy duty trucks and buses, and non road diesel equipment.

Against this backdrop of Federal actions that lower air emissions ( As well as some substantial State control programs), States will develop plans designed to achieve the standards in their local nonattainment areas. The EPA has not yet promulgated rules interpreting the CAA's requirements for SIPs for PM2.5 and ozone nonattainment 225 9 EPA did promulgate Phase I of the ozone implementation rule in April 2004 ( 69 FR 23951; April 30, 2004) but has not issued Phase II of the rule, which will interpret CAA requirements relating to local controls ( e. g., RACT, RACM, RFP). areas, 59 nor have States developed plans to demonstrate attainment. As a result, there are significant uncertainties regarding potential reductions and control costs associated with State plans. We believe that some areas are likely to attain the standards in the near term through early CAIR reductions and local controls that have costs per ton similar to the levels we have determined to be highly cost effective. We expect that other areas with higher PM2.5 or ozone levels will determine through the attainment planning process that they need greater emissions reductions, at higher costs per ton, to reach attainment within the CAA's timeframes. For those areas, States will need to assess targeted measures for achieving local attainment in a cost effective ( but not necessarily highly cost effective) manner, in combination with the CAIR's significant reductions. Given the uncertainties that exist at this early stage of the implementation process, EPA believes this rule is a rational approach to determining the highly cost effective reductions in PM2.5 and ozone precursors that should be required for interstate transport purposes. 226 As discussed above, the Agency believes this approach is consistent with our action in the NOx SIP Call. While the cost level selected for the NOx SIP Call was not at the low end of the reference range of costs, if the NOx SIP Call costs were for annual rather than seasonal controls they would have been lower relative to the annual control costs on the list. This would make the relationship between the cost of the NOx SIP Call and the reference costs used in that rulemaking, more similar to relative costs of CAIR compared to its reference lists. Also, significant local controls for meeting the 1 hour ozone standard had already been adopted in many areas.

Although EPA's primary cost effectiveness determination is for the 2015 emissions reductions levels, the Agency also evaluated the cost effectiveness of the interim phase control levels to ensure that they were also highly cost effective. For the SO2 requirements for 2010, the average cost effectiveness is $ 500 per ton removed, and the marginal cost effectiveness ranges from $ 700 to $ 800. The 2010 costs indicate that the interim phase CAIR reductions are also highly cost effective.

( IV) Cost Effectiveness: Marginal Cost Curves for SO2 Control As noted above, the Agency also considered another 227 factor to corroborate its conclusion concerning the cost effectiveness of the selected levels of control: the cost effectiveness of alternative stringency levels for today's action. Specifically, EPA examined changes in the marginal cost curve at varying levels of emissions reductions for EGUs. Figure IV 1 shows that the " knee" in the 2010 marginal cost effectiveness curve   the point where the cost of controlling a ton of SO2 from EGUs is increasing at a noticeably higher rate   appears to occur at about $ 2,000 per ton of SO2. Figure IV 2 shows that the " knee" in the 2015 marginal cost effectiveness curve also appears to occur at about $ 2,000 per ton of SO2. ( As discussed above, the projected marginal costs of SO2 reductions for the CAIR are $ 700 per ton in 2010 and $ 1,000 per ton in 2015.) The EPA used the Technology Retrofitting Updating Model ( TRUM), a spreadsheet model based on the IPM, for this analysis. ( The EPA based these marginal SO2 cost effectiveness curves on the electric growth and natural gas price assumptions in the main CAIR IPM modeling run. Marginal cost effectiveness curves based on other electric growth and natural gas price assumptions would look different, therefore it would not be appropriate to compare the curves here to the marginal costs based on the IPM modeling sensitivity run that used EIA assumptions.) These results make clear that this rule is 228 10 EPA is using the knee in the curve analysis solely to show that the required emissions reductions are very cost effective. The marginal cost curve reflects only emissions reduction and cost information, and not other considerations. We note that it might be reasonable in a particular regulatory action to require emissions reductions past the knee of the curve to reduce overall costs of meeting the NAAQS or to achieve benefits that exceed costs. It should be noted that similar analysis for other source categories may yield different curves. Marginal Cost Curve of Abatement for SO2 Emissions from EGUs in 2010 ( NOx Emissions at 1.5 million tons)

$ $ 500 $ 1,000 $ 1,500 $ 2,000 $ 2,500 $ 3,000 1.00 2.00 3.00 4.00 5.00 6.00 Million Tons of SO2 Emitted in CAIR Region Source: EPA TRUM Analysis, August 2004 Marginal Cost ( 1999$/ ton)

SO2 Price ($/ ton) Figure IV 1. very cost effective because the control level is below the point at which the cost begins to increase at a significantly higher rate.

In this manner, these results corroborate EPA's findings above concerning the cost effectiveness of the emissions reductions. 60 229 Marginal Cost Curve of Abatement for SO2 Emissions from EGUs in 2015 ( NOx Emissions at 1.3million tons)

$ $ 500 $ 1,000 $ 1,500 $ 2,000 $ 2,500 $ 3,000 1.00 2.00 3.00 4.00 5.00 6.00 7.00 Million Tons of SO2 Emittedin CAIR Region Source: EPA TRUM Analysis, August 2004 Marginal Cost ( 1999$/ ton)

SO2 Price ($/ ton) Figure IV  2.

b. NOx Emissions Reductions Requirements i. The CAIR Proposal for NOx and Subsequent Analyses for Regionwide Annual and Ozone Season NOx Control Levels In this section, EPA describes its proposed method for determining regionwide NOx control levels and the method used for the final CAIR.

In the CAIR NPR, EPA updated the reference list included in the NOx SIP Call for the average annual cost effectiveness of recent or proposed NOx controls, and determined that these amounts ranged from approximately $ 200 230 to $ 2,800. In addition, in the NPR, EPA developed a reference list for marginal annual cost effectiveness for NOx controls, and determined that these amounts ranged from approximately $ 1,400 to $ 3,000 ( 69 FR 4614  4615).

In the NPR, EPA proposed a two phased annual NOx control program, with a final phase in 2015 and a first phase in 2010. The regionwide emissions reduction requirements that EPA proposed   and the budget levels that would apply if all States chose to implement the reductions from EGUs   were based on using a combination of recent historical heat input and NOx emissions rates for fossil fuel fired EGUs. For historical heat input, EPA proposed determining the highest heat input from units affected by the Acid Rain Program for each affected State for the years 1999 2002. The EPA then summed this heat input for all of the States affected for annual NOx reductions. For 2015,

EPA calculated a proposed regionwide annual NOx budget by multiplying this heat input by an emission rate of 0.125 lb/ mmBtu, and for 2010 by multiplying by 0.15 lb/ mmBtu.

In developing the CAIR NPR, when EPA considered the appropriate amount of annual SO2 emissions reductions, EPA relied on the existing title IV annual SO2 cap as a starting point. However, in considering the appropriate amount of NOx reductions, the situation is different because title IV 231 does not cap NOx emissions. Therefore, EPA and the States have focused on emissions caps based on a combination of heat input and NOx emission rates. Emission rates similar to the rates used to develop the CAIR NPR have been considered in the past. For example, the CAPI 1996 study,

noted above, contemplated NOx caps based on an emission rate of 0.15 lb/ mmBtu ( and other options based on NOx rates of 0.20 lb/ mmBtu and 0.25 lb/ mmBtu). The NOx SIP Call is based on an emission rate of 0.15 lb/ mmBtu.

The methodology described in the NPR is best understood as the means for developing the target 2015 annual NOx control level ( or emissions budget) for further evaluation through IPM. The EPA developed this level mindful of its experience to date with the NOx SIP Call and the earlier work EPA has performed on multi pollutant power plant reduction programs. The EPA also considered available technical information on pollution controls, costs to industry and the general public, ambient air improvement,

and consistency with the emerging PM2.5 implementation program, in developing its target control level.

Recent advances in combustion control technology for NOx reductions, as well as widespread use of selective catalytic reduction ( SCR) on U. S. coal fired EGU boilers achieving NOx emission rates of 0.06 lb/ mmBtu and below, 232 provide evidence that even lower average NOx emission rates are more highly cost effective than rates considered in the past ( based on analyzing EGUs), possibly on the order of 0.12 lb/ mmBtu or less. The EPA developed the target annual NOx control level ( or emissions budget) with the understanding that the evaluation of that level might indicate that average emission rates on the order of 0.12 lb/ mmBtu or less might be highly cost effective for the final ( 2015) control phase, and an interim level resulting in an average emission rate of less than 0.15 lb/ mmBtu might be feasible for the first phase.

The EPA did evaluate the target annual NOx control levels ( or emissions budgets) using the IPM. The EPA confirmed that the 2015 level is highly cost effective. The Agency also evaluated the cost effectiveness of the proposed 2010 cap to assure that the interim phase reductions would also be highly cost effective. The EPA's IPM analyses for the CAIR includes all fossil fuel fired EGUs with generating capacity greater than 25 MW.

The proposed cap for the first phase was developed taking into consideration how much pollution control for NOx and SO2 could be installed without running into a shortage of skilled labor, in particular boilermakers ( EPA's assumptions regarding boilermaker labor are described in 233 11 The EPA does not collect annual heat input data from these non Acid Rain units. EIA does collect heat input from such units, however there are some limitations to the data. First, there are no requirements specifying how the data should be collected or quality assured. Second, the data is collected on a plant wide basis rather than on a unit byunit basis. section IV. C. 2 of this preamble). The Agency focused on providing substantial reductions of both SO2 and NOx emissions at the outset of the proposed program, leading to significant retrofits of Flue Gas Desulfurization units ( FGD) for SO2 control and SCR for NOx control.

In the NPR, EPA explained that using the highest Acid Rain Program heat input for each State to develop a regionwide heat input amount, rather than the average Acid Rain Program heat input, provided a cushion that represented a reasonable adjustment to reflect that there are some non Acid Rain units that operate in these States that will be subject to the proposed CAIR emission reduction levels.

The EPA explained that it did not use heat input data from non Acid Rain units in the proposal because it did not have all the necessary data available at the time the NPR was developed. 61 Using the highest of recent years' Acid Rain Program heat input provided an approximation of the regionwide heat input, although it did not include heat input from non Acid Rain sources. Multiplying the approximate recent heat input by 0.125 lb/ mmBtu to develop a 234 proposed regionwide annual 2015 NOx cap could reasonably be expected to yield an average effective NOx emission rate ( considering all EGUs potentially affected by CAIR for annual reductions, not only the Acid Rain units, and considering growth in heat input) somewhat less than 0.125 lb/ mmBtu. Likewise, multiplying the approximate recent heat input by 0.15 lb/ mmBtu to develop a regionwide annual 2010 NOx cap could reasonably be expected to yield an average effective NOx emission rate for all CAIR units of about 0.15 lb/ mmBtu or less.

Although EPA calculated   in essence, as a target level for further evaluation   the proposed regionwide annual NOx control levels ( or emissions budgets) based on heat input from only Acid Rain Program units, the Agency evaluated the cost effectiveness of the control levels using heat input from all EGUs that potentially would be affected by the proposed CAIR. The EPA evaluated cost effectiveness using the IPM, which includes both Acid Rain units and non Acid Rain units. Further, the IPM incorporates assumptions for electricity demand growth, and thus heat input growth.

Specifically, EPA evaluated these target annual NOx caps on EGUs for 2010 and 2015   and therefore the associated regionwide emissions reductions   using the IPM,

which, in effect, demonstrated that these proposed NOx 235 12 These projected average NOx emissions rates are from updated IPM modeling done in 2004. The IPM modeling done prior to the NPR also projected similar average emission rates, about 0.15 lb/ mmBtu and 0.11 lb/ mmBtu in 2010 and 2015, respectively. emissions cap levels can be met using highly cost effective controls with the expected levels of electricity demand in 2010 and 2015, respectively. Those expected levels of electricity demand are higher than the electricity demand during the 1999 to 2002 years upon which EPA based heat input; and as a result, the amount of heat input necessary to meet the projected electricity demand is expected to be higher than the amount that EPA developed for evaluation purposes through the method described above. The projected average future emissions rates that would be associated with the 2010 and 2015 heat input levels needed to meet electricity demand ( coupled with the NOx emissions budgets developed through the methodology described above) would be about 0.14 lb/ mmBtu and 0.11 lb/ mmBtu in 2010 and 2015,

respectively. 62 These average rates would be for all units affected by annual NOx controls under CAIR, including non

Acid Rain units. Thus, the heat input is projected to be higher in 2010 and 2015 than the recent historic heat input used to develop the target emissions budgets, and the projected NOx emission rates in 2010 and 2015 are lower than the 0.15 lb/ mmBtu and 0.125 lb/ mmBtu rates that were used to 236 develop the budgets. IPM determined the costs of meeting these average future NOx emission rates of 0.14 lb/ mmBtu and 0.11 lb/ mmBtu. EPA considers these emission rates to be highly cost effective and feasible.

In the NPR, EPA proposed an interim ( Phase I) annual NOx phase in 2010 and a final ( Phase II) annual NOx phase in 2015. However, in today's final rule, EPA is promulgating a Phase I for NOx in 2009 ( with the Phase II for NOx in 2015,

as proposed). EPA determined the regionwide NOx control levels for 2009 and 2015 for today's final action using the same methodology as we used to determine proposed levels.

The Agency evaluated the cost effectiveness of the final reduction requirements ( and average NOx emission rates)

using IPM and determined them to be highly cost effective,

assuming controls on EGUs. EPA's evaluation of the cost effectiveness of the emission reduction strategy we assumed in establishing the final CAIR control levels is discussed further below.

The average NOx emission rates in the first and second phases of CAIR will be lower than the nominal emission rate on which the NOx SIP Call was based, which was 0.15 lb/ mmBtu. In the NOx SIP Call, EPA also considered a control level based on a lower nominal emission rate, 0.12 lb/ mmBtu. However, at that time the use of SCR was not 237 sufficiently widespread to allow EPA to conclude that the controls necessary to meet a tighter cap could be installed in the required timeframe, without causing reliability problems for the electric power sector. Now, through the experience gained from the NOx SIP Call, EPA has confidence that with SCR technology average emissions rates lower than the NOx SIP Call nominal emission rate can be achieved on a regionwide basis.

In the CAIR NPR, after determining the regionwide control level and evaluating it to assure that it is highly cost effective, the Agency then apportioned the regionwide budgets to the affected States. The EPA proposed to apportion regionwide NOx budgets to individual States on the basis of each State's share of recent average heat input.

In the NPR, EPA used the average share of Acid Rain Program heat input. However, as discussed in the SNPR and the NODA,

in order to distribute more equitably to States their share of the regionwide NOx budgets, EPA then considered each State's proportional share of recent average heat input using data from non Acid Rain Program sources as well as Acid Rain Program sources. The EPA obtained EIA heat input data reported for non Acid Rain sources and combined the EIA heat inputs with Acid Rain heat inputs to determine each State's share of combined average recent heat input. 238 The fact that EPA distributed the regionwide budget to individual States based on their proportional share of heat input from Acid Rain and non Acid Rain units combined does not affect the determination of the regionwide budgets themselves. The regionwide budgets were determined to be highly cost effective when tested for all units   both non

Acid Rain units as well as Acid Rain units   that would be affected by CAIR. ( EPA's method for apportioning regionwide NOx budgets to States is discussed in more detail elsewhere in today's preamble. That discussion includes an explanation of the differences between the State budgets that were presented in the NPR, the SNPR, and the NODA. In addition, see the TSD entitled " Regional and State SO2 and NOx Emissions Budgets.")

In the NPR, EPA proposed that Connecticut contributed significantly to downwind ozone nonattainment, but not to PM2.5 nonattainment. Thus, the Agency proposed that Connecticut would not be subject to an annual NOx control requirement and was not included in the region proposed for annual controls. We proposed that Connecticut would be affected by an ozone season only NOx control level, and proposed to calculate Connecticut's ozone season control level in a parallel way to how the regionwide annual NOx control levels were calculated. That is, EPA selected the 239 highest of the same 4 years of ( ozone season only) heat input used for the regionwide budget calculation, and multiplied that heat input by the same NOx emission rates used to calculate the regionwide control levels.

Connecticut is the only State for which an ozone season budget was proposed.

The EPA used the same methodology for developing regionwide budgets for today's final rule as was proposed in the NPR. For the final CAIR, EPA found that 23 States and the District of Columbia contribute significantly to downwind PM2.5 nonattainment and found that 25 States and the District of Columbia contribute significantly to downwind ozone nonattainment ( section III in today's preamble describes the significance determinations). CAIR requires annual NOx reductions in all States determined to contribute significantly to downwind PM2.5 nonattainment,

and requires ozone season NOx reductions in all States determined to contribute significantly to downwind ozone nonattainment ( many of the CAIR States are affected by both annual and ozone season NOx reduction requirements). The final CAIR ozone season NOx reductions are required in two phases, with Phase I commencing in 2009 and Phase II in 2015, the same years as the annual NOx reduction requirements. 240 As described above, the Agency proposed ozone season NOx reduction requirements for Connecticut, and did not propose ozone season reductions in any other State. For today's final rule, EPA requires ozone season reductions in all States contributing significantly to downwind ozone nonattainment. The EPA determined regionwide ozone season NOx control levels for the final CAIR using the same methodology as was used for the annual NOx reduction requirements ( which is the same method that was proposed for Connecticut's ozone season budget). That is, EPA determined the highest ( ozone season) heat input from Acid Rain Program units for the years 1999 2002 for each State, then summed this heat input for all of the States affected for ozone season NOx reductions. For the final 2015 control level,

EPA calculated a regionwide ozone season NOx budget by multiplying this heat input by an emission rate of 0.125 lb/ mmBtu, and for 2009 by multiplying by 0.15 lb/ mmBtu. The Agency evaluated the cost effectiveness of these ozone season NOx control levels ( and average NOx emission rates)

using IPM and determined them to be highly cost effective,

assuming controls on EGUs. EPA's evaluation of the cost effectiveness of the final CAIR control requirements is discussed further below.

Based on EPA's analysis of proposed annual NOx control 241 13 The control costs for this model sensitivity that were presented in the NPR were in error ( 69 FR 4615). The corrected costs from the sensitivity are as shown here. levels, in the NPR the Agency presented average costs for annual NOx control of $ 800 per ton and $ 700 per ton for 2010 and 2015, and marginal costs of $ 1,300 per ton and $ 1,500 per ton for 2010 and 2015. In the NPR, EPA also presented marginal costs of annual NOx control from sensitivity analyses that used EIA assumptions for electricity growth and natural gas prices. Those marginal control costs were $ 1,300 per ton and $ 1,600 per ton for 2010 and 2015,

respectively. The EPA also presented costs from a sensitivity model run that used EIA assumptions for electricity growth and natural gas price and higher SCR costs. These marginal control costs were $ 1,700 per ton and $ 2,200 per ton for 2010 and 2015, respectively. 63 In the NPR, EPA also presented the average cost effectiveness for ozone season only NOx control of $ 1,000 per ton and $ 1,500 per ton for 2010 and 2015, respectively,

and a marginal cost for ozone season only control of $ 2,200 per ton and $ 2,600 per ton for 2010 and 2015. The EPA also presented average costs for the non ozone season ( remaining seven months of the year) control of $ 700 per ton and $ 500 per ton in 2010 and 2015, respectively. ( As noted above,

the capital costs of installing NOx control equipment would 242 be largely identical whether the equipment will be operated during the ozone season only or for the entire year.

However, the amount of reductions would be less if the control equipment were operated only during the ozone season compared to annual operation.)

EPA proposed the conclusion that these costs met the criteria for highly cost effective emissions reductions for NOx ( 69 FR 4613  4615).

As with SO2, EPA also considered the cost effectiveness of alternative stringency levels for this regulatory proposal ( examining changes in the marginal cost curve at varying levels of emission reductions).

ii. What Are the Most Significant Comments that EPA Received about Proposed NOx Emission Reduction Requirements,

and What Are EPA's Responses?

Some commenters expressed concern that EPA did not account for growth of heat input in calculating regionwide NOx emissions budgets, noting that growth was used in the calculation of the regional budget for the NOx SIP Call.

Commenters suggest that, by not taking heat input growth into account, EPA developed regionwide budgets that are unduly stringent.

On the other hand, some commenters noted that they supported EPA's proposal to base regionwide budgets on 243 historical heat input and did not want EPA to use growth projections for calculating regionwide NOx emissions budgets. Some stated that using actual, historic heat input numbers would be more straightforward than using growth projections, and some pointed to complications with the growth projection methodologies used in the NOx SIP Call.

EPA recognizes that it employed a growth factor in the NOx SIP Call. There, EPA determined the amount of the regional emissions reductions and budgets by applying a growth factor to a historic heat input baseline. The D. C.

Circuit, after first remanding that growth methodology for a better explanation, upheld it. West Virginia v. EPA, 362 F. 3d 861 ( D. C. Cir., 2004). See 67 FR 21 868 ( May 1, 2002).

For CAIR, as described above, EPA developed a target level for the proposed NOx regionwide cap based on recent historic heat input and assumed emission rates of 0.125 lb/ mmBtu and 0.15 lb/ mmBtu for 2015 and 2010, respectively.

The EPA evaluated these target NOx emissions levels using IPM, which indicated that those target caps   in conjunction with expected electricity demand for 2015 and 2010   would result from higher heat input levels and lower average emissions rates ( about 0.11 lb/ mmBtu and 0.14 lb/ mmBtu for 2015 and 2010, respectively) than the amounts assumed in developing the target NOx caps. Most importantly, IPM 244 indicated the cost levels associated with those projected 2015 and 2010 average NOx emission rates, and EPA has determined that those cost levels are highly cost effective.

For the final rule, EPA revised its analyses to reflect the 2009 initial NOx control phase, and determined that the final CAIR requirements are highly cost effective. EPA's methodology, in which the CAIR emissions reductions are predicted to be cost effective under conditions of projected electricity growth that, in turn, projects heat input growth, in effect accounts for heat input growth. Moreover,

the amount of heat input growth is the amount determined by IPM, a state of the art model of the electricity sector ( detailed documentation for IPM is in the docket).

Some commenters suggested that EPA adjust the NOx regionwide budget amounts to include heat input from non

Acid Rain units. For example, some suggested adding the non Acid Rain unit heat input amounts that EPA used in apportioning regionwide NOx budgets to the States, to the total regionwide heat inputs that EPA used to calculate regionwide NOx budgets.

The regionwide budgets determined in the NPR were target levels developed as a starting point for further evaluation. The regionwide heat input amounts and NOx emission rates used to develop target budget levels were 245 inherently imprecise. As discussed above, IPM modeling indicates that the projected future heat input amounts ( based on electricity growth) are greater than the recent historic regionwide amount used to develop the target budget levels, and the future average emission rates for all units affected by CAIR annual NOx controls ( including non Acid Rain units) are less than the rates used to develop the target budget levels. IPM indicates that the target regionwide NOx budget levels ( and corresponding future average NOx emission rates and heat input levels) are highly cost effective for all CAIR units, including non Acid Rain units. The EPA does not believe it is necessary to adjust the target regionwide budget levels to include the relatively small additional amount of heat input from non

Acid Rain units. The method the Agency used to develop target levels was not intended to be a precise methodology for determining the NOx caps; rather, it was a reasonable method for selecting a target level to be evaluated further.

Upon evaluation of the target level, EPA determined that it can be achieved using highly cost effective controls for all affected EGUs, including non Acid Rain units.

iii. Analysis of NOx Emission Reduction Requirements for Today's Final Rule ( I) Reference Lists of Cost Effective Controls 246 64 The updated reference list includes estimated average NOx control costs under BART. The BART rule has been proposed but not finalized ( 69 FR 25184; May 5, 2004). For today's action, EPA updated the reference list of controls included in the NPR of the average and marginal costs per ton of recent NOx control actions. The EPA systematically developed a list of cost information from recent actions and proposed actions. The Agency sought cost information for actions taken by EPA, and examined the comments submitted after the NPR was published, to identify all available control cost information to provide the updated reference list for today's preamble. The updated reference list includes both average and marginal costs of control to which EPA compares the CAIR control costs,

although the Agency has limited information on marginal costs of other programs.

The EPA's updated summary of average costs of annual NOx controls are shown in Table IV 6. The results of this reexamination show that costs of recent actions are generally very similar to those identified in the NOx SIP Call. The cost figures are presented in 1999 dollars. 64 247 Table IV 6. Average Costs per Ton of Annual NOx Controls NO x Control Action Average Cost per Ton Marine Compression Ignition Engines Up to $ 200 2 Off highway Diesel Engine $ 400  $ 700 2 Nonroad Diesel Engines and Fuel $ 600 1 Marine Spark Ignition Engines $ 1,200  $ 1,800 2 Tier 2 Vehicle Gasoline Sulfur $ 1,300  $ 2,300 2 Revision of New Source Performance Standards for NOx Emissions  EGUs $ 1,700 3 2007 Highway Heavy Duty Diesel Standards $ 1,600  $ 2,100 2 National Low Emission Vehicle $ 1,900 2 Tier 1 Vehicle Standards $ 2,100  $ 2,800 2 Revision of New Source Performance Standards for NOx Emissions  Industrial Units $ 2,200 3 On board Diagnostics $ 2,300 2 Texas NO x Emission Reduction Grants FY 2002  2003 $ 300  $ 12,700 4 Best Available Retrofit Technology ( BART) for Electric Power Sector $ 800 5 1 Control of Emissions of Air Pollution From Nonroad Diesel Engines and Fuel; Final Rule ( 69 FR 39131; June 29, 2004). The value in this table represents the long term cost per ton of emissions reduced from the total fuel and engine program ( cost per ton of emissions reduced in the year 2030). This value includes the cost for NOx plus NMHC reductions. 1999$ per ton. 2 Control of Air Pollution from New Motor Vehicles: Heavy Duty Engine and Vehicle Standards and Highway Diesel Fuel Sulfur Control Requirements; Final Rule ( 66 FR 5102; January 18, 2001). The values shown for 2007 Highway HD Diesel Stds are discounted costs. Costs shown in this table include a VOC component. 1999$ per ton. 3 Proposed Revision of Standards of Performance for Nitrogen Oxide Emissions From New Fossil Fuel Fired Steam Generating Units; Proposed Revision to Reporting Requirements for Standards of Performance for New Fossil Fuel Fired Steam Generating Units; Proposed Rule ( 62 FR 36953; July 9, 1997), Table 4 ( the Agency's estimate of average control costs was unchanged for the NSPS revisions final rule, published September 5, 1998). In the CAIR NPR, we included a value from the range of NOx controls for coal fired EGUs from Table 2 in the proposed NSPS proposed rule ( 62 FR 36951). 1999$ per ton. 4 Costs shown in this table are the range of project costs reported for projects that were FY 2002  2003 recipients of the TERP Emission Reductions Incentive Grants Program. These costs may not be in 1999 dollars. ( www. tnrcc. state. tx. us/ oprd/ sips/ grants. html) 5 The EPA IPM modeling 2004 of the proposed BART for the electric 248 power sector ( 69 FR 25184, May 5, 2004), available in the docket. The EPA modeled the Regional Haze Requirements as a source specific 0.2 lb/ mmBtu NOx emission rate limit. Estimated average costs based on this modeling are $ 800 per ton in 2015 and 2020. 1999$ per ton.

Table IV 7 presents modeled marginal costs for recent State annual NOx rules.

Table IV 7. Marginal Costs per Ton of Reduction, Recent Annual NOx Rules NO X Control Action Marginal Cost per Ton Texas Rules $ 2,000  $ 19,600 1 1 The EPA IPM Base Case modeling August 2004, available in the docket. 1999$ per ton. We modeled Senate Bill 7 and Ch. 117, which impose varying NOx control requirements in different areas of the State; the range of marginal costs shown here reflects the range of requirements.

The EPA does not believe that it has sufficient information, for today's rulemaking, to treat controls on source categories other than certain EGUs as providing highly cost effective emissions reductions. The CAA Section 110 permits States to choose the sources and source categories that will be controlled in order to meet applicable emission and air quality requirements. This means that some States may choose to meet their CAIR obligations by imposing control requirements on sources other than EGUs.

As examples of cost effective actions that States can take in efforts to provide for attainment with the air quality standards, Table IV 8 presents estimated average costs for potential local mobile source NOx control actions. 249 The EPA received these cost data during the public comments on the NPR.

Table IV 8. Average Costs of Potential Local Mobile Source Control Actions to Reduce NOx Emissions ($ per Ton) 1 Source Category Average Cost per Ton MWCOG Analysis: Mobile Source, Bicycle racks in DC $ 9,000 MWCOG Analysis: Mobile Source, Telecommuting Centers $ 7,300 MWCOG Analysis: Mobile Source, Government Action Days ( ozone action days) $ 5,000 MWCOG Analysis: Mobile Source, Permit Right Turn on Red $ 1,200 MWCOG Analysis: Mobile Source, Employer Outreach $ 3,500 MWCOG Analysis: Mobile Source, Mass Marketing Campaign $ 2,900 MWCOG Analysis: Mobile Source, Transit Prioritization $ 8,500 1 Washington DC Metro Area MWCOG Analysis of Potential Reasonably Available Control Measures ( RACM). Projects determined to be " Possible" by MWCOG but not RACM because benefits from the possible control measures do not meet the 8.8 tpd NOx or 34.0 tpd VOC threshold necessary for RACM. These costs may not be in 1999 dollars. ( www. mwcog. org/ uploads/ committee documents/ z1ZZXg20040217144350. pdf) Comments submitted to the EPA CAIR docket from the Clean Air Task Force et al., dated March 30, 2004, included costs from the MWCOG analysis.

( II) Cost Effectiveness of CAIR Annual NOx Reductions Table IV 9 provides the average and marginal costs of annual NOx reductions under CAIR for 2009 and 2015. These costs are updated from the NPR figures   the EPA analyzed the costs of the CAIR using an updated version of IPM ( documentation for the IPM update is in the docket).

Further, EPA modified the modeling to match the final CAIR strategy ( see section IV. A. 1 for a description of EPA's CAIR IPM modeling). 250 15 The CSP consists of 200,000 tons, which is apportioned to each of the 23 States and the District of Columbia that are required by CAIR to make annual NOx reductions, as well as the 2 States ( Delaware and New Jersey) for which EPA is proposing to require annual NOx reductions. CAIR provides for a Compliance Supplement Pool ( CSP) of NOx allowances that can be used for compliance with the annual NOx reduction requirements. The CSP is discussed in detail later in this preamble. The EPA used IPM to model marginal costs of CAIR with the CSP. The magnitude of the NOx CSP is relatively small compared to the annual NOx budget, 65 thus the CSP does not significantly impact the marginal costs ( see Table IV 9).

As with SO2 marginal costs, EPA considered the sensitivity of the NOx marginal cost results to assumptions of higher electric growth and future natural gas prices than the Agency used in the base case, as shown in Table IV 9.

Table IV 9. Estimated Costs per Ton of Annual NOx Controlled Under CAIR 1 Type of Cost Effectiveness 2009 2015 Average Cost  Main Case $ 500 $ 700 Marginal Cost  Main Case $ 1,300 $ 1,600 Marginal Cost B With Compliance Supplement Pool ( CSP) $ 1,300 $ 1,600 Sensitivity Analysis: Marginal Cost Using Alternate Electricity Growth and Natural Gas Price Assumptions $ 1,400 $ 1,700 1 The EPA IPM modeling 2004, available in the docket. 1999$ per ton.

These estimated NOx control costs under CAIR reflect 251 annual EGU NOx caps of 1.5 million tons in 2009 and 1.3 million tons in 2015 within the CAIR annual NOx control region ( the 23 States and DC that must make annual reductions). In both the main IPM modeling case and the modeling case that includes the CSP, projected annual NOx emissions in the CAIR region will be about 1.5 million tons in 2009 and 1.3 million tons in 2015. The projected emissions are very similar in both modeling cases because the CSP is relatively small compared to the annual NOx budget.

Average costs shown for 2015 are based on the amount of reductions that would achieve the total difference in projected emissions between the base case conditions and CAIR in the year 2015. These costs are not based on the increment in reductions between 2009 and 2015. ( A more detailed description of the final CAIR SO2 and NOx control requirements is provided later in today's preamble.)

Most of the States subject to today's PM2.5 control requirements have been subject to the NOx SIP Call requirements. Some sources in these States have installed SCRs, and run them during the ozone season. These sources might comply with the PM2.5 annual NOx requirements by, at least in part, running the SCR controls for the remaining months of the year. Under these circumstances, the 252 compliance costs for the PM2.5 SIP requirements are lower.

Table IV 10 provides estimated costs per ton of NOx for non ozone season reductions under CAIR. These figures are updated from the NPR calculations   the EPA analyzed the costs of the CAIR using an updated version of IPM ( documentation for the IPM update is in the docket) and modeled controls on a region that more closely matches the region affected by CAIR.

Table IV 10. Predicted Costs per Ton of Non Ozone Season NOx Controlled Under CAIR 1 Type of Cost Effectiveness 2009 2015 Average Cost $ 500 $ 500 1 The EPA IPM modeling 2004, available in the docket. 1999$ per ton.

The estimated non ozone season NOx costs, like the annual NOx costs, are on the low end of the cost effectiveness range described in Table IV 6. The EPA considers the 2015 and also the 2009 costs to represent highly cost effective controls.

Environmental Defense reached similar conclusions regarding the cost effectiveness of non ozone season NOx reductions, as described in their report " A Plan for All Seasons: Costs and Benefits of Year Round NOx Reductions in Eastern States ( 2002)." As stated in that report, "[ As Figure 4 shows,] extending NOx reductions throughout the 253 year results in dramatic decreases in the per ton costs of NOx emission reductions for the 19 NOx SIP Call States.

This is because the bulk of the cost for reducing NOx emissions from power plants lies in the capital investment in the control equipment. Once the primary investment has been made, it costs relatively little to continue running the control equipment beyond the summer months required by EPA's NOx SIP Call." Environmental Defense based these conclusions on analysis conducted by Resources for the Future ( RFF). In an RFF paper, " Cost Effective Reduction of NOx Emissions from Electricity Generation ( July 2001)," RFF draws similar conclusions.

( III) NOx Cost Comparison for CAIR Requirements The EPA believes that selecting as highly costeffective amounts at the lower end of these average and marginal cost ranges is appropriate for reasons explained above in this section of the preamble.

As discussed above, although in the NOx SIP Call the cost level selected was not at the low end of the reference range of costs, if the NOx SIP Call costs were for annual rather than seasonal controls they would have been lower relative to the other control costs on the reference list which were mostly for annual programs.

For annual NOx, the range of average cost effectiveness 254 extends broadly, from under $ 200 to thousands of dollars ( Table IV 6). The 2015 estimated average costs for CAIR annual NOx control of $ 700 are consistent with the lower end of this range.

Less information is available for the marginal costs of controls than for average costs. Looking at the available marginal costs ( Table IV 7), the 2015 CAIR marginal costs for annual NOx controls are at the lower end of the range.

The EPA also evaluated the cost effectiveness of the 2009 cap, and concluded that the 2009 requirements are highly cost effective.

( IV) Cost Effectiveness: Marginal Cost Curves for Annual NOx Control As with SO2 controls, EPA also considered the cost effectiveness of alternative stringency levels for NOx control for today's action by examining changes in the marginal cost curve at varying levels of emissions reductions. Figure IV 3 shows that the " knee" in the 2010 marginal cost effectiveness curve for EGUs   the point where the cost of controlling a ton of NOx begins to increase at a noticeably higher rate   appears to occur at over $ 1,700 per ton of NOx. Although EPA conducted this marginal cost curve analysis based on an initial NOx control phase in 2010, the 255 16 EPA is using the knee in the curve analysis solely to show that the required emissions reductions are very cost effective. The marginal cost curve reflects only emissions reduction and cost information, and not other considerations. We note that it might be reasonable in a particular regulatory action to require emissions reductions past the knee of the curve to reduce overall costs of meeting the NAAQS or to achieve benefits that exceed costs. results would be very similar for 2009, which is the initial NOx phase in the final CAIR. Figure IV 4 shows that the " knee" in the 2015 marginal cost effectiveness curve for EGUs appears to occur at over $ 1,700 per ton of NOx. ( The EPA based these marginal NOx cost effectiveness curves on the electricity growth and natural gas price assumptions in the main CAIR IPM modeling run. Marginal cost effectiveness curves based on other electric growth and natural gas price assumptions would look different, therefore it would not be appropriate to compare the curves here to the marginal costs based on the IPM modeling sensitivity run that used EIA assumptions.) The EPA used the Technology Retrofitting Updating Model ( TRUM), a spreadsheet model based on IPM, for this analysis. These results make clear that this rule is very cost effective because the control level is below the point at which the cost begins to increase at a significantly higher rate.

In this manner, these results corroborate EPA's findings above concerning the cost effectiveness of the emissions reductions. 66 256 As in the case of SO2 controls, described above, it should be noted that similar analysis for other source categories may yield different curves. 257 M a rg in a l C o st C u rv e o f A b a te m e n t fo r A n n u a l N O X Em issio n s fro m EG U s in 2 0 1 0 ( S O 2 Em issio n s a t 5 .3 m i l l io n to n s)

$ 1 ,0 0 0 $ 1 ,5 0 0 $ 2 ,0 0 0 $ 2 ,5 0 0 $ 3 ,0 0 0 0 .5 0 1 .0 0 1 .5 0 2 .0 0 2 .5 0 M illio n T o n s o f N O x Em it te d in C A IR R e g io n S o u r c e : EP A T RU M A n a lys is , A u g u s t 2 0 0 4 Marginal Cost ( 1999$/ ton) N O x P r ic e ($ / to n )

Marginal Cost Curve of Abatement for Annual NOX Emissions from EGUs in 2015 ( SO2 Emissions at 4.1 million tons)

$ 1,000 $ 1,500 $ 2,000 $ 2,500 $ 3,000 0.50 1.00 1.50 2.00 2.50 Million Tons of NOx Emitte d in CAIR Re gion Source : EPA TRUM Analy sis, August 2004 Marginal Cost ( 1999$/ ton)

NOx Price ($/ ton) Figure IV 3 Figure IV 4 258 ( V) Cost Effectiveness of Ozone Season NOx Reductions The CAIR requires ozone season NOx emissions reduction for all States determined to contribute significantly to ozone nonattainment downwind ( 25 States and the District of Columbia). The EPA used IPM to model average and marginal costs of the ozone season reductions assuming EGU controls.

In this modeling case, EPA modeled an ozone season NOx cap for the region affected by CAIR for downwind ozone nonattainment, but did not include the CAIR annual SO2 or NOx caps. Based on that modeling, Table IV 11 provides estimated average and marginal costs of regionwide ozone season NOx reductions for 2009 and 2015. Table IV 11 shows the estimated cost effectiveness of today's ozone season NOx control requirements for 8 hour transport SIPs.

Table IV 11. Estimated Costs per Ton of Ozone Season NOx Controlled Under CAIR 1 Type of Cost Effectiveness 2009 2015 Average Cost $ 900 $ 1,800 Marginal Cost $ 2,400 $ 3,000 1 The EPA IPM modeling 2004, available in the docket. 1999$ per ton.

These estimated NOx control costs are based on ozone season EGU NOx caps of 0.6 million tons in 2009 and 0.5 million tons in 2015 within the CAIR ozone season NOx 259 17 For both the NOx SIP Call and CAIR, the NOx control costs on the reference lists are generally for annual reductions. The EPA compared the costs of ozone season reductions under the NOx SIP Call, as well as ozone season CAIR NOx reductions, to the annual reduction programs on the reference lists. control region. Average costs shown for 2015 are based on the amount of reductions that would achieve the total difference in projected emissions between the base case conditions and CAIR in the year 2015. These costs are not based on the increment in reductions between 2009 and 2015.

( A more detailed description of the final CAIR SO2 and NOx control requirements is provided later in today's preamble.)

The EPA believes that selecting as highly costeffective amounts at the lower end of the average and marginal cost ranges is appropriate for reasons explained above in section IV in this preamble.

In the NOx SIP Call, EPA identified average costs of $ 2,500 ( 1999$) ( or $ 2,000 ( 1990$)) as highly costeffective 67 The estimated average costs of regionwide ozone season NOx control under CAIR are $ 1,800 per ton in 2015 and $ 900 per ton in 2009. Thus, with respect to average costs the controls for the final phase ( 2015) cap,

which are below the $ 2,500 identified in the NOx SIP Call,

are also highly cost effective, as are those for the 2009 cap. In addition, the estimated average costs of CAIR ozone 260 18 In the NOx SIP Call EPA used average, not marginal, costs to evaluate cost effectiveness. For the reasons discussed above we are evaluating both average and marginal costs for CAIR. season NOx control are at the lower end of the reference range of average annual NOx control costs ( the reference list of average annual NOx control costs is presented above).

Similarly, the estimated marginal costs68 of ozone season CAIR NOx controls are within EPA's reference range of marginal costs, at the lower end of the range ( the reference list of marginal annual NOx control costs is presented above). We note that the marginal costs in the reference range are for annual NOx reductions, and would likely be higher for ozone season only programs. Considering both average and marginal costs, the CAIR ozone season control level is highly cost effective.

For purposes of estimating costs of ozone season control under CAIR, EPA set up this modeling case with CAIR ozone season NOx requirements but without the annual NOx requirements. The Agency believes that the cost of the ozone season CAIR requirements will actually be lower than the costs presented here because interactions will occur between the CAIR annual and ozone season NOx control 261 19 Estimated costs for regionwide CAIR NOx controls during the ozone season are higher than the average and marginal costs for CAIR annual NOx controls. This is because, as noted above, the capital costs of installing NOx control equipment would be largely identical whether the SCR will be operated during the ozone season only or for the entire year. However, the amount of reductions would be less if the control equipment were operated only during the ozone season compared to annual operation. requirements. 69 In addition, for States in both programs,

the same controls achieving annual reductions for PM purposes will achieve ozone season reductions for ozone purposes; this is not reflected in our cost per ton estimates.

As with SO2 controls, and annual NOx controls, EPA also considered the cost effectiveness of alternative stringency levels for CAIR NOx reductions for ozone purposes by examining changes in the marginal cost curve at varying levels of emissions reductions. Figure IV 5 shows that the " knee" in the 2010 marginal cost effectiveness curve for ozone season NOx reductions from EGUs   the point where the cost of controlling an ozone season ton of NOx begins to increase at a noticeably higher rate   appears to occur somewhere between $ 3,000 and $ 4,000 per ton of NOx.

Although EPA conducted this marginal cost curve analysis based on an initial NOx control phase in 2010 the results would be very similar for 2009, which is the initial NOx phase in the final CAIR. Figure IV 6 shows that the " knee" 262 20 EPA is using the knee in the curve analysis solely to show that the required emissions reductions are very cost effective. The marginal cost curve reflects only emissions reduction and cost information, and not other considerations. We note that it might be reasonable in a particular regulatory action to require emissions reductions past the knee of the curve to reduce overall costs of meeting the NAAQS or to achieve benefits that exceed costs. As in the case of SO2 controls, described above, it should be noted that similar analysis for other source categories may yield different curves. in the 2015 marginal cost effectiveness curve for ozone season NOx reductions from EGUs appears to occur somewhere between $ 3,000 and $ 4,000 per ton of NOx. The EPA used the Technology Retrofitting Updating Model ( TRUM), a spreadsheet model based on the IPM, for this analysis. These results make clear that CAIR NOx reductions for ozone purposes are very cost effective because the control level is below the point at which the cost begins to increase at a significantly higher rate.

In this manner, these results corroborate EPA's findings above concerning the cost effectiveness of the emissions reductions. 70 263 Marginal Cost Curve of Ozone Season NOx Abatement in 2010 ( Base case SO2 emissions)

$ 2,000 $ 2,500 $ 3,000 $ 3,500 $ 4,000 $ 4,500 $ 5,000 $ 5,500 $ 6,000 $ 6,500 $ 7,000  0.10 0.20 0.30 0.40 0.50 0.60 0.70 Million Tons of NOx Emitted in CAIR Ozone Region during Ozone Season Marginal Cost ( 1999 $/ ton)

NOx Price ($/ ton)

Results using TRUM; IPM results would differ. Figure IV 5 264 M a r g in a l C o s t C u r v e o f O z o n e S e a s o n N O x A b a te m e n t in 2 0 1 5 ( B a s e c a s e S O 2 e m is s io n s )

$ 2 ,0 0 0 $ 2 ,5 0 0 $ 3 ,0 0 0 $ 3 ,5 0 0 $ 4 ,0 0 0 $ 4 ,5 0 0 $ 5 ,0 0 0 $ 5 ,5 0 0 $ 6 ,0 0 0 $ 6 ,5 0 0 $ 7 ,0 0 0  0 .1 0 0 .2 0 0 .3 0 0 .4 0 0 .5 0 0 .6 0 0 .7 0 M i l l i o n T o n s o f N O x E m i t t e d i n C A IR O z o n e R e g i o n d u r i n g O z o n e S e a s o n Marginal Cost ( 1999 $/ ton) N O x P r ic e ($ / to n )

R e s u lts u s in g T R U M ; IP M r e s u lts w o u ld d if fe r . Figure IV 6 265 B.   What Other Sources Did EPA Consider when Determining Emission Reduction Requirements?

1.   Potential Sources of Highly Cost Effective Emissions Reductions In today's rulemaking, EPA determines the amount of regionwide emissions reductions required by determining the amount of emissions reductions that could be achieved through the application of highly cost effective controls on certain EGUs. The EPA has reviewed other source categories,

but concludes that for purposes of today's rulemaking, there is insufficient information to conclude that highly cost effective controls are available for other source categories.

b. Mobile and Area Sources In the NPR ( 69 FR 4610), EPA explained that " it did not identify highly cost effective controls on mobile or area sources." No comments were received suggesting that mobile or area sources should be controlled. Therefore, in developing emission reduction requirements, EPA is not assuming any emissions reductions from mobile or area sources.

b.   Non EGU Boilers and Turbines The largest single category of stationary source non

EGUs are large non EGU boilers and turbines. This source 266 category emits both SO2 and NOx. In the CAIR NPR, EPA proposed not to include any potential SO2 or NOx emissions reductions from non EGU boilers and turbines as constituting " highly cost effective" reductions and thus to be taken into account in establishing emissions requirements because EPA believed it had insufficient information on their control costs, particularly costs associated with the integration of NOx and SO2 controls. In addition, based on information EPA does have, projected base case ( without the CAIR) emissions of SO2 and NOx from these sources are significantly lower than projected EGU emissions. The EPA projects that in 2010 under base case conditions, EGUs would contribute 70 percent of SO2 in the CAIR region compared to 15 percent from non

EGU boilers and turbines in the CAIR region. The Agency also predicts that in 2010 under the base case, EGUs would contribute 25 percent of NOx emissions in the CAIR region compared to 16 percent from non EGU boilers and turbines in the CAIR region. Thus, simply on an absolute basis, non EGU emissions are relatively less significant than emissions from EGUs. The EPA is finalizing its proposed approach to these sources and has not based today's requirements on any presumed availability of highly cost effective emissions reductions from non EGU boilers and turbines.

A number of commenters believe EPA should determine 267 that emissions reductions from non EGUs should be taken into account in establishing emission requirements because, they believe, highly cost effective controls are available for these sources. These commenters argued that highly costeffective controls are available for these sources and that EPA should have sufficient emissions and control cost information because the same sources were included in the NOx SIP Call.

In addition, while it is true that these sources were included in the NOx SIP Call, EPA only addressed NOx reductions from these sources. Neither SO2 reductions nor monitoring of SO2 emissions is required by the NOx SIP Call.

As a result, for these sources, EPA has less reliable SO2 emissions data and very little information on the integration of NOx and SO2 controls. Although EPA has more information on NOx emissions from these sources because of the NOx SIP Call ( and other programs in the northeastern U. S.), the geographic coverage of the CAIR includes some States that were not included in the NOx SIP Call, some of which States contain significant amounts of industry. The EPA has even less emissions data from non EGUs in these non SIP call States affected by the CAIR. While EPA has incorporated State submitted emissions inventory data for 1999 into its analysis for the CAIR, even this data is 268 generally lacking information on fuel, sulfur content, and existing controls. Without this data, it is very difficult to assess the emission reduction opportunities available for non EGU boilers and turbines. Furthermore, with regards to NOx, many non EGU boilers and turbines are making reductions using low NOx burners ( the control technology EPA assumed in making the cost effectiveness determinations in the NOx SIP Call). Since these controls are operated year round, annual emissions reductions are already being obtained from many of these units. Additional reductions would likely be less cost effective.

Another commenter stated that non EGU " major sources"

are subject to the requirements of title V of the CAA and,

therefore, EPA should have adequate emissions data provided as part of the sources' permitting obligations. However,

title V simply requires that a source's permit include the substantive requirements ( such as emission monitoring requirements) imposed by other sections of the CAA and does not itself impose any substantive requirements. Thus, the mere fact that a source is a major source required to have a title V permit does not mean that the source is monitoring and submitting emissions, fuel, and control device data.

Many such sources do not, in fact, provide such data.

One commenter submitted cost information for FGD 269 technology applications on industrial boilers. However, the information submitted by the commenter was based on the use of a limited number of technologies and for a limited number of boiler sizes. The EPA does not believe that the limited information demonstrates that SO2 emissions from these sources could be controlled in a highly cost effective manner across the entire sector in question, or to what level the emissions could be controlled.

Some commenters recommended including non EGU boilers and turbines because in the future, after reductions from EGUs are made, the relative contribution of non EGU boilers and turbines to the total NOx and SO2 emissions will increase. The EPA agrees that the relative contribution of non EGUs to total NOx and SO2 emissions will increase in the future if States choose to meet their CAIR emissions reduction obligations solely by way of emission reductions made by EGUs. However, EPA does not believe that this, by itself, provides any basis for determining that in the context of this rule emissions reductions from non EGUs should be determined to be highly cost effective. As discussed above, EPA believes it is necessary to have more reliable emissions data and better control cost information for these sources before assuming reductions from them in the CAIR. The EPA is working to improve its inventory of 270 emissions and control cost information for non EGU boilers and turbines. Specifically, we are assessing the emission inventory submittals for 2002 made by States in response to the relatively new requirements of 40 CFR part 51 ( the Consolidated Emission Reporting Rule), and we will work with States whose submissions appear to have gaps in required data. We also note that EPA provides financial and technical support for the efforts of the five Regional Planning Organizations to coordinate among and assist States in improving emission inventories.

Another commenter expressed concern that if the decision whether to control large industrial boilers is left to the States, the result may be inequitable treatment of EGUs on a State by State basis, particularly with respect to allowances, and therefore it would make sense to require NOx and SO2 reductions from large industrial boilers. Section 110 of the CAA leaves the ultimate choice of what sources to control to the States, and EPA cannot require States to control non EGUs. Even if EPA had included reductions from non EGUs in determining the total amount of reductions required under the CAIR, EPA could not have required any State to achieve those reductions through emission limitations on non EGUs.

The recent economic circumstances faced by the 271 manufacturing sector accentuates EPA's concerns about the lack of reliable emissions data and control information regarding non EGUs. We note that the U. S. manufacturing sector was adversely affected by the latest business cycle slowdown. As noted in the 2004 Economic Report of the President, the manufacturing sector was hit earlier, longer,

and harder than other sectors of the economy. The 2004 Report also points out that, although manufacturing output has dropped much more than the real gross domestic product ( GDP) during past business cycles, the latest recovery has been unusual because it has been weaker for the manufacturing sector than the recovery in the real GDP. The disparity across sectors ( and even within individual sectors) in the economic condition of firms reinforces EPA's concerns about moving forward to consider emission controls on non EGUs at this time.

As explained elsewhere in this preamble, although the CAIR does not require that States achieve the required emissions reductions by controlling particular source categories, we expect that States will meet their CAIR obligations by requiring emissions reductions from EGUs because such reductions are highly cost effective. We believe the States are in the best position to make decisions regarding any additional control requirements for 272 non EGU sources. In making such decisions, States may take into consideration all relevant factors and information,

such as differences across States in the need for control,

differences in relative contribution of various sources, and differences in the operating and economic conditions across sources.

c.   Other Non EGU Stationary Sources In the NPR and in the technical support document entitled " Identification and Discussion of Sources of Regional Point Source NOx and SO2 Emissions Other Than EGUs ( January 2004)," EPA applied a similar rationale for non EGU stationary sources other than boilers and turbines. For SO2, EPA noted that the emissions from such sources were a relatively small part of the emissions inventory, and we also noted the lack of information on costs. For NOx, we explained that more information was available than for SO2.

This is because the NOx SIP Call included consideration of emissions control measures for internal combustion ( IC)

engines and cement kilns, and developed cost estimates for other NOx emitting categories such as process heaters and glass manufacturing. However, we believed   as for boilers and turbines, discussed above   that insufficient information on emission control options and costs, was available to apply these measures to the entire geographic 273 area covered by the proposed rule.

No adverse comments were received suggesting inclusion of SO2 emissions reductions from non EGU stationary sources other than boilers and turbines. Accordingly, EPA has determined not to consider SO2 reductions from these other non EGU stationary sources.

Several commenters suggested that EPA should have been able to consider NOx emissions reductions from non EGU categories other than boilers and turbines, such as internal combustion ( IC) engines and refinery fluid catalytic cracking units. These commenters believed such reductions were demonstrated to be cost effective, and questioned EPA's assertion that insufficient information is available.

Finally, some commenters believe EPA should have, at a minimum, required that controls for NOx SIP Call sources   including large IC engines and cement kilns   should be extended from the ozone season to the entire year.

We believe it likely that inclusion in today's requirements of reductions from any highly cost effective controls   if available   for these categories would have very small effects. First, most of the States included in the CAIR rule were also included in the NOx SIP Call, so that many of the emissions reductions that would be available from these sources have already occurred due to 274 implementation of the NOx SIP Call. Second, in the States included in the CAIR rule, but which were not covered by the NOx SIP Call, only a small portion of NOx emissions come from cement kilns and IC engines compared to EGUs.

Moreover, in some parts of this geographic area, in particular for Texas, many sources in these source categories are already regulated under ozone nonattainment plans ( including SIPs for the Texas cities of Houston,

Galveston, and Dallas).

Regarding the commenters' recommendation that extending NOx SIP Call control requirements to a year round basis for large IC engines and cement kilns should be considered to be highly cost effective, EPA believes that few emissions reductions would be achieved from doing so. The types of controls that were applied in the NOx SIP Call States, while required to be in place only during the ozone season, will,

as a practical matter, be applied on a year round basis,

whether or not so required by today's rule. Most, if not all, of the NOx SIP Call States have developed regulations to control NOx emissions from IC engines and cement kilns during the ozone season. The control of choice to meet these reductions from large lean burn IC engines is low emission combustion ( LEC), which for retrofit applications is a substantial equipment modification of the engine's 275 combustion system. The engine will operate with LEC year round because this modification is a permanent change to the engine. Most, if not all, new large lean burn IC engines have LEC. In addition, year round emissions controls are already required for rich burn engines greater than 500 hp which will likely install nonselective catalyst reduction to comply with the recently adopted hazardous air pollutant standards ( see final rule for reciprocating IC engines, 69 FR 33474, June 15, 2004). For cement kilns, the controls of choice are low NOx burners and mid kiln firing. Low NOx burners ( LNB) are a permanent part of the kiln, so that the kiln will operate year round with LNB. Mid kiln firing is a kiln modification for which a solid and slow burning fuel ( typically tires) is injected in the mid kiln area. Due to tipping fees and fuel credits, mid kiln firing results in an operating cost savings. After this system is installed,

year round operation is expected.

C. Schedule for Implementing SO2 and NOx Emissions Reduction Requirements for PM2.5 and Ozone 1. Overview In the NPR, EPA proposed a two phased schedule for implementing the CAIR annual emission reduction requirements: implementation of the first phase would be required by January 1, 2010 ( covering 2010 2014), and that 276 for the second phase by January 1, 2015 ( covering after 2014). The EPA based its proposal on its analysis of engineering, financial, and other factors that affect the timing for installing the emission controls that would be most cost effective   and are therefore the most likely to be adopted  for States to meet the CAIR requirements.

Those air pollution controls are primarily retrofitted FGD systems ( i. e., scrubbers) for SO2 and SCR systems for NOx on coal fired power plants.

The EPA's projections showed a significant number of affected sources installing these controls. The proposed two phased schedule allowed the implementation of as much of the controls as feasible by an early date, with a later time for the remaining controls.

The EPA received detailed, technical comments from commenters who argued that the controls could not be implemented until later than proposed, and from other commenters who argued that the controls could be implemented sooner than proposed. The EPA has reviewed the comments and has conducted additional research and analyses to verify availability of adequate industrial resources, including boilermakers, for constructing the emission control retrofits required by CAIR. These analyses are based on conservative assumptions, including those suggested by the 277 21 The NOx SIP Call Rule allowed approximately 3 1/ 2 years for implementation of all NOx Controls. commenters, to ensure that the requirements imposed by CAIR do not result in shortages of the required resources that could substantially increase construction costs for pollution controls and reduce the cost effectiveness of this program.

Today, EPA is taking final action to require the annual emissions reductions on the same two phase schedule as proposed. However, the requirements for the first phase include two separate compliance deadlines: implementation of NOx reductions are required by January 1, 2009 ( covering 2009 2014) and for SO2 reductions by January 1, 2010 ( covering 2010 2014). The compliance deadline requirements for the second phase are the same as proposed. The EPA believes that its action is consistent with the Agency's obligations under the CAA to require emission reductions for obtaining NAAQS to be achieved as soon as practicable. The EPA applied the same criterion in implementing the NOx SIP Call, which was based on a single phased schedule. 71 2. Engineering Factors Affecting Timing for Control Retrofits a. NPR In the NPR, EPA identified the availability of 278 boilermakers as an important constraint for the installation of significant amounts of SCR and FGD retrofits.

Boilermakers are skilled laborers that perform various specialized construction activities, including welding and rigging, for boilers and high pressure vessels. The air pollution control devices, such as scrubber and SCR vessels,

require boilermakers for their construction. Apprentices with no prior work related experience complete a four year training program, to become full boilermakers. For apprentices with relevant experience, this training period could be shorter. For example, union members representing the shipbuilding trade could be expedited into the boilermaker division within a year.

The boilermaker constraint was considered more important for the initiation of the first phase of CAIR,

since the NOx SIP Call experience had shown that many sources would be adverse to committing significant funds to install controls until after SIPs were finalized. With the States required to finalize SIPs in 18 months after the signing of the final rule, the sources would have three years in which to complete purchasing, construction, and startup activities associated with these controls, to meet the proposed CAIR deadline.

The EPA's projections showed power plants installing 279 51.4 gigawatts ( GW) of FGD and 28.2 GW of SCR retrofits during the first CAIR phase. These projections include retrofits for CAIR as well as retrofits for Base Case policies ( i. e., retrofits for existing regulatory requirements). We estimated the total boilermaker years required for installing these controls at 12,700, which was based on the boilermakers being utilized over a period of 18 months during the installation process. Also, based on the projected boilermaker population in the timeframe relevant to the installation of these controls, we estimated that 14,700 boilermaker years were available over the same 18 month period. The availability of approximately 15 percent more boilermaker years than required, as shown by these estimates, confirms the adequacy of this critical resource for CAIR and EPA assumed this to be a reasonable contingency factor.

The EPA also determined that installation of the projected amounts of FGD and SCR retrofits could be completed within the three year period available for CAIR.

This determination was based on a previous report prepared by EPA for the proposed Clear Skies Act, " Engineering and Economic Factors Affecting the Installation of Control Technologies for Multi Pollutant Strategies," ( docket no.

OAR 2003 0053 0106). According to this report, an average 280 of 21 months are required to install SCR on one unit, and 27 months to install a scrubber on one unit. For multiple units within the same plant, installation of controls would normally be staggered to avoid operational disruptions. The EPA projected that the maximum number of multiple unit controls required for each affected facility could all be installed within three years. The NPR proposal included a second phase, with a compliance deadline of January 1, 2015.

The EPA's projections showed power plants installing 19.1 GW of FGD and 31.7 GW of SCR retrofits by 2015, which included retrofits for CAIR as well as retrofits for Base Case policies ( i. e., retrofits for existing regulatory requirements). Availability of boilermaker labor was not an important constraint for this phase.

b. Comments The EPA received several comments relating to the requirements for the two phased implementation program, the emission caps and compliance deadline for each phase, and resources required to install necessary controls. The commenters offered opposing viewpoints, which can be broadly categorized as follows:

i. Several commenters indicated that the compliance deadline of 2010 for the first phase was not attainable and argued that EPA should either extend the deadline, or set 281 higher emission caps for this phase. The commenters raised the following specific points in support of their concerns:

( I) The time allowed for completing various activities from planning to startup of the required controls was not sufficient. Other related activities, including project financing and obtaining a landfill permit for the scrubber waste, could also require more time than what the rule allowed. In addition, the short implementation period would require simultaneous outages of too many units to tie the new equipment into the existing systems, which would affect the reliability of the electrical grid.

( II) Implementation of controls to the required large number of units would cause shortages in the supply of critical industrial resources, especially boilermakers. An analysis performed by a commenter showed a shortfall in the supply of boilermaker labor during the construction period relevant to CAIR retrofits. This commenter anticipated that certain key variables would be greater in value than those used by EPA and based their analysis on higher SCR prices, EIA projected higher natural gas prices and electricity demand factors,

and more stringent boilermaker duty rates ( boilermaker year/ MW) and availability factors.

ii. Commenters who favored more stringent compliance deadlines argued that the required controls could be 282 installed in less time and more controls could be built in early years. These commenters raised the following specific points in support of their concerns:

( I) The compliance deadlines for the two phases did not support the ozone and fine particulate ( PM2.5) attainment dates mandated by the CAA. The Phase I deadline should be accelerated to meet these attainment dates. Sufficient industrial resources, including boilermakers, would be available to support such an acceleration. While some commenters supported an earlier Phase I deadline of January 1, 2008, the others supported a deadline of January 1, 2009.

Some of these commenters also suggested that the Phase I deadline be accelerated only for NOx.

( II) The EPA's estimates for the boilermaker availability were too conservative. A boilermaker labor analysis performed by one commenter showed an adequate supply of this resource to support installation of all Phase I and II controls by the start of the first phase ( by 2010), thereby eliminating the need for two phases.

( III) The time allowed for installing controls for Phase II was excessive. The initiation of this phase could be moved forward.

iii. Several commenters supported EPA's assumptions used in support of the adequacy of the implementation period and 283 resources to build the required CAIR controls. These assumptions included the overall construction schedule durations for SCR and FGD systems and boilermaker unit rates.

c. Responses The EPA reviewed the above comments and performed additional research and analyses, including new IPM runs that incorporated higher SCR and natural gas costs and greater electric demand. We also found that more units had installed SCR under the NOx SIP Call and other regulatory actions than what our records previously showed. This increase in the number of existing SCR installations was also incorporated into these IPM runs. In addition, the number of existing FGD installations was also revised slightly downward, for the same reason.

The revised IPM analyses for today's final action show that the amounts of controls that need to be put on for Phase I are 39.6 GW of FGD and 23.9 GW of SCR. These amounts represent a reduction from the estimates for the NPR. For Phase II, the amount of the required controls are 32.4 GW of FGD and 26.6 GW of SCR. These amounts represent an increase from the estimates for the NPR. The amounts shown for both phases reflect all retrofits required for the CAIR and Base Case ( non CAIR) policies. The retrofit 284 projections for the Base Case policies are included, since some of the available boilermaker labor would be consumed in building these retrofits during the CAIR time frame.

The EPA also contacted the International Brotherhood of Boilermakers ( IBB), U. S. Bureau of Labor Statistics ( BLS),

and National Association of Construction Boilermaker Employers ( NACBE) to verify its assumptions on boilermakers population, percentage of boilermakers available to work on the control retrofit projects, and average annual hours of boilermaker employment. Except for the boilermaker population, the information received as a result of these investigations validated EPA's assumptions. IBB also confirmed that the boilermaker population would at least be maintained at the current level of 26,000 members, during the period relevant to construction of CAIR retrofits. It did not want to forecast growth and historically has not done so. Therefore, instead of the 28,000 boilermaker forecasted population used in the NPR, we have conservatively used a boilermaker population of 26,000 for the final CAIR. A detailed discussion on these assumptions and the information received from these sources is available in the docket to this rulemaking as a technical support document ( TSD), entitled " Boilermaker Labor and Installation Timing Analysis." 285 The responses to the most significant comments on these issues are summarized in the following sections.

i. Issues Related to Compliance Deadline Extension ( I) Adequacy of Phase I Implementation Period Today's action initiates State activities in conjunction with EPA to set up the administrative details of CAIR. With the first phase compliance deadline of January 1, 2009, for NOx and January 1, 2010, for SO2, the affected sources would have approximately 3 3/ 4 and 4 3/ 4 years for the implementation of the overall requirements for this phase, respectively. The final SIPs would be submitted at the end of the first 18 months of these implementation periods. The remaining 2 1/ 4 and 3 1/ 4 years would be available for the sources to complete activities required for the procurement and installation of NOx and SO2 controls,

respectively. For the reasons outlined below, EPA believes that these deadlines provide enough time to install the required Phase I controls.

( A) Engineering/ Construction Schedule Issues The EPA notes that, for CAIR, the States would finalize the SIPs in 18 months after the rule is signed, and that until then, the majority of sources required to install controls may not initiate activities that require commitment of major funds. However, some activities, such as planning, 286 preparation of conceptual designs, selection of technologies, and contacts with equipment suppliers can be started or completed prior to the finalization of SIPs, at least for major sources expected to require longer implementation periods. In addition, other activities, such as permitting and financing can be started after the rule is finalized. This is based on the NOx SIP Call experience.

After the SIPs are finalized, the sources would have approximately 2 1/ 4 and 3 1/ 4 years in which to complete purchasing, detailed design, fabrication, construction, and startup of the required NOx and SO2 controls, respectively.

This assumes that activities, such as planning and selection of technologies, have already been started or completed,

prior to the start of these 2 1/ 4 and 3 1/ 4 year periods.

As discussed in the NPR proposal, EPA projects an average single unit installation time of 21 months for SCR and 27 months for a scrubber. Our revised IPM analysis for the final rule shows that many facilities would install controls on multiple units ( a maximum of six for SCR and five for FGD) at the same plant. We expect these facilities to stagger these installations to minimize operational disruptions.

The EPA also projects that SCRs and scrubbers could be installed on the multiple units in the available time 287 periods of 2 1/ 4 and 3 1/ 4 years, respectively. The issues related to the availability of boilermakers and the ability of the plants requiring multiple unit controls to stagger their installations during these periods are discussed later in this preamble.

As compared to projections in the NPR proposal, earlier signing of the final rule adds approximately three additional months to the overall implementation periods for SO2 controls. Furthermore, EPA's projections for the final rule show fewer Phase I NOx and SO2 controls being added than the projections in the NPR proposal. Since the compliance deadline for NOx has been moved up a year from the proposal,

a three month earlier rule promulgation provides more time for implementing SO2 controls only. However, since it does allow use of critical resources, such as boilermakers, for SO2 controls to be spread over a longer period of time, the net effect would be to make more of these resources available for both SO2 and NOx controls ( as compared to a scenario where promulgation was not three months earlier).

This is especially true since the implementation periods for both NOx and SO2 controls would start at the same time and the plants installing these controls would be competing for the same resources until January 1, 2009, the compliance deadline for NOx. The EPA, therefore, believes that 2 1/ 4 288 and 3 1/ 4 year time periods provide reasonable amounts of time from the approval of State programs by September 2006,

until the commencement of compliance deadlines for meeting the NOx and SO2 emission requirements.

Certain commenters have provided their own estimates of schedule requirements for installing the required controls.

In some cases, these estimates are longer than those determined by EPA. For scrubbers, including spray dryer and wet limestone or lime type systems, the control implementation requirements provided by the commenters range from 30 to 54 months for the overall project and 18 to 36 months for the phase following equipment awards. In this case, the lowest 18 month schedule requirement cited applies to spray dryers, whereas the shortest schedule cited for wet scrubbers for the activities following the equipment awards is 24 months. For SCR, the control implementation requirements cited by the commenters range from 24 to 36 months for the overall project and 17 to 25 months for the phase following the equipment awards.

One commenter has pointed out that the construction schedule requirements for the FGD and SCR retrofit projects have shortened, because of the lessons learned from a significant number of such projects completed during the last few years. The EPA notes that a recent announcement 289 22 Reference: Announcement by Wheelabrator Air Pollution Control Inc. for award of a wet limestone scrubber system for K. C. Coleman Generating Station, Western Kentucky Energy Corp., August 2, 2004, and other related documents. ( docket no. OAR 2003 0053 1953) for a new 485 MW limestone scrubber facility indicates a construction schedule duration ( from equipment award to startup) of only 18 months. 72 This is well below the schedule requirement cited by the commenters for a wet limestone scrubber.

The EPA also notes that most of the commenters'

schedule estimates are consistent with the time periods available for completing the CAIR related NOx and SO2 projects. Some of the longer schedules submitted by commenters would exceed the CAIR Phase I dates. However,

EPA considers these longer schedules to be speculative, as these commenters did not justify them. The major factors that influence schedule requirements include size of the installation, degree of retrofit difficulty, and plant location. The EPA does not expect these factors to make a difference of more than a few months between the schedule requirements of various installations. The commenters who have cited long schedule requirements that fall at the higher end of the above ranges have not provided any data to support the wide differences between their schedules and those proposed by others, including EPA. It should also be 290 23 Summary of telephone calls with States to discuss landfill permit timing ( docket no. OAR 2003 0053 1927) noted that EPA's schedules are based on information from several actual SCR and scrubber installations. Therefore,

EPA cannot accept the excessive schedule requirements proposed by these commenters.

( B) Landfill Permit Issue The EPA contacted several key States requiring FGD retrofits, to investigate the amount of time required to obtain a landfill permit for scrubber waste. We note that not all scrubber installations would require landfills, as some scrubber designs produce saleable waste products, such as gypsum.

Specifically, EPA contacted Georgia, Ohio, Indiana,

Alabama, Pennsylvania, West Virginia, Tennessee, and Kentucky. 73 Except for Kentucky, all States indicated that their permit approval periods ranged from 12 to 27 months.

Some of these States indicated that permit approval may require more time than 27 months, but only for the cases in which major landfill design issues persist or the permit applicant has not provided complete and proper information with the permit application.

The Kentucky Department of Environmental Protection indicated that, based on their historical records, the 291 average permit approval period was 3 1/ 2 years. They also stated that the State was sensitive to an applicant's time restrictions and the permit approval times had varied depending on the level of urgency surrounding a permit application. They further confirmed that they would work with the industry to meet compliance deadlines, such as those required by CAIR, as efficiently as possible.

Based on the above investigations, EPA notes that the landfill permitting requirements quoted by all States fall well within the 4 3/ 4 year implementation period for Phase I. Also, landfill permitting activities as well as its design and construction can be accomplished, independent of the design and construction of the FGD system. The EPA,

therefore, believes that landfill permitting is not a constraint for compliance with the rule.

( C) Project Financing Issue Commenters representing small units or units owned by the co operatives raised concerns that arrangement of financing for control retrofits could take long periods of time. However, EPA's projections show a larger portion of the smaller units installing controls only during the second phase. These projections also show that only a few co operative units would require installation of controls.

Therefore, EPA believes that the Phase I implementation 292 periods of approximately 3 3/ 4 and 4 3/ 4 years for NOx and SO2 controls, respectively, provide enough time for completing the financing activity for all controls. Of course, if individual sources face difficulties in meeting deadlines to implement controls, they may use the allowance trading provisions of CAIR to defer implementation of controls.

( D) Electrical Grid Reliability Issue Based on available data for the NOx SIP Call,

approximately 68 GW of SCR retrofits were started up during the years from 2001 to 2003. This included approximately 42 GW of SCRs in 2003 alone, which exceeds the combined capacity of SCR and FGD retrofits for CAIR that we expect to be started up in any one year. The EPA projects that startup of the 23.9 GW of SCR and 39.6 GW of FGD capacity required for Phase I would be spread over a period of two years ( 2008 and 2009). The total capacity of units starting up in each year is therefore expected to be approximately 32 GW ( half of the combined SCR and FGD capacity of 63.5 GW).

The NOx SIP Call experience shows that outages required to complete installation of the large SCR capacity,

especially during 2003, did not have an adverse impact on the electrical grid reliability. The EPA notes that the outage requirement for SCR usually exceeds that for 293 24 Reference: " NERC, Generating Availability Data System: All MW Sizes  Coal Fired Generation Report, http:// www. nerc. com/~ filez/ gar. html, October 17, 2003 scrubbers, since SCR is located closer to the boiler and it may be more intrusive to the existing equipment. As shown above, the CAIR retrofits are projected to include more scrubbers than SCRs and the capacity of these retrofits starting up in any one year is below the capacity of the NOx SIP Call units that started up in 2003. Therefore, the overall outage requirement for CAIR would be less than that experienced for the NOx SIP Call.

Based on published industry data, the planned outage times for coal fired units from 2001 2002 ( SCR buildup years) decreased by over two percent compared to the previous two years from 1998 1999.74 The reduction in the overall outage time in the 2001 2002 period also shows that the SCR retrofits did not adversely affect the grid reliability. Therefore, EPA believes that the concern regarding electrical grid reliability is unwarranted for CAIR retrofits.

( II) Availability of Boilermaker Labor in Phase I The EPA has performed several analyses to verify the adequacy of the available boilermaker labor for the installation of CAIR's Phase I controls. These analyses were not just based on using EPA's assumptions for the key 294 factors affecting the boilermaker availability, but also the assumptions suggested by commenters for these factors to determine how sure we could be on our key conclusions. If there was insufficient labor for the amount of air pollution controls that will need to be installed, the program would be in jeopardy. For instance, shortages in manpower could lead to high wage rates that could substantially increase construction costs for pollution controls and reduce the cost effectiveness of this program. During the peak of the NOx SIP Call SCR construction period, the power industry did experience an increase in the SCR construction costs. One of the reasons cited for these higher costs was an increased demand for boilermaker labor. The EPA strongly wanted to avoid this possibility for CAIR. The EPA also wanted to be very sure that the levels of controls and timing of the program's start were appropriate. Therefore, EPA tended to make conservative assumptions and to test the sensitivity of key assumptions that were uncertain.

Boilermakers population, percentage of boilermakers available to work on the control retrofit projects, and average annual hours of boilermaker employment are some of the key factors that affect boilermaker availability. As discussed previously, EPA's assumptions on these factors 295 were validated or revised through our discussions with IBB,

BLS, and NACBE.

Two other key factors that also have an impact on boilermaker availability include the number of required SCR and FGD retrofits and boilermaker duty rates (

boilermakeryear MW, i. e., the number of boilermaker years needed to install SCR or FGD on one MW of electric generation capacity). The EPA's projections for the required SCR and FGD retrofits are based on the IPM analyses performed for the final rule. The basis for the boilermaker duty rates used by EPA is a report prepared by EPA for the proposed Clear Skies Act, " Engineering and Economic Factors Affecting the Installation of Control Technologies for Multi Pollutant Strategies."