Response: The commenters and EPA agree that LEC technology is a proven technology for natural gas fired lean burn engines. 30 There is not agreement, however, on the appropriate level of control to assume from installation of the LEC technology. In response to comments, we collected additional test data, including data representative of emissions from large engines in the NOx SIP Call area. To determine the appropriate level of control, we examined all available data, including data from State permits and test data on new, rebuilt, and retrofit engines with LEC technology. These data were placed in the docket. A summary of the data is provided below. As suggested by commenters, the data have been organized to show LEC retrofit test data for large engine models found in the NOx Draft   Do not cite, quote or distribute 95 SIP Call area.

The INGAA in their April 22, 2002 comments, identified the most common models of large natural gas transmission engines in the NOx SIP Call area. In addition, INGAA identified engines that had been retrofit with LEC in the NOx SIP Call area. In response to these comments, we contacted the various EPA Regional Offices to obtain information on specific large lean  burn engines used by the gas pipeline industry that have been retrofit with LEC in the NOx SIP Call area. Data from the EPA Regional Offices and other emission test results were obtained. The results for large engines in the NOx SIP Call area show that 43 of the 58 tests have NOx emission levels at or below 3.0 g/

bhphr ( see RTC or TSD for details). The LEC technology retrofit on these large engines achieved, on average, an emission rate of 2.3 g/ bhp hr.

As suggested by commenters, we also examined the available data separately for 2 and 4 stroke engines ( see TSD for details). Test data for the large IC engines in the NOx SIP Call area indicate controlled levels of 2.3 and 2.5,

respectively, for the 2 and 4 stroke engines. Assuming 85 percent of the engines in the NOx SIP Call area are 2

stroke, the weighted average of the 2.3 and 2.5 values is 2.3. Draft   Do not cite, quote or distribute 31 " Stationary Reciprocating Internal Combustion Engines: Updated Information on NOx Emissions and Control Techniques," EC/ R Incorporated, September 1, 2000, page 4 5 ( Docket No. OAR 2001 0008 ( Legacy Docket No. A 96 56), Item No. XII K 43).

96 As described in the TSD, looking at a broader set of data yields similar results. That is, considering data from large engines both inside and outside the NOx SIP Call area shows that 60 of the 79 tests have NOx emission levels at or below 3.0 g/ bhp hr ( see TSD for details). The LEC technology retrofit on these large engines achieved, on average, an emission rate of 2.2 g/ bhp hr. Considering the similarity of the resulting average controlled emission rates and the ample set of data for large engines in the NOx SIP Call area, we agree with commenters that it is reasonable to focus on the set of data for large engines in the NOx SIP Call area.

The set of data for large engines in the NOx SIP Call area cover 80 percent of the engine models in the NOx SIP Call area. However, emission rates for some of the engine models for which test data are not available are likely to be higher than the 2.3 average value. For example,

Worthington and Nordberg engines are known to be difficult to retrofit. One vendor reported achieving a level of 6 g/ bhp hr for certain Worthington engines. 31 As noted in the Draft   Do not cite, quote or distribute 32 Docket No. OAR 2001 0008 ( Legacy Docket No. A 96 56), Item No. XII D 24.

97 TSD, a Worthington UTC 165 in New York reduced NOx emissions to 4.4 g/ hp hr. A pipeline company commented that they operate six Worthington engines and that 4.0 g/ bhp hr is their targeted emission reduction level, based on vendor projections. 32 Thus, it appears that a 4.0 to 6.0 g/ bhp hr level is achievable on these difficult to retrofit Worthington engines. At this time, we believe that 5.0 g/ bhp hr is a reasonable emission rate, on average, for engines known to be difficult to retrofit. Although not all of the 20 percent of engine models for which test data are not available are likely to be difficult to retrofit, we believe it is reasonable to treat these engines as one group and to conservatively assume that this group of engines would achieve a 5.0 level, on average.

In summary, based on the available test data, we believe it is reasonable to assume about 80 percent of the large engines in the NOx SIP Call area are able to meet a 2.3 level, on average, and that 20 percent are able to meet a 5.0 level, on average with LEC technology. Thus,

calculating the weighted average for installation of LEC technology retrofit on all of these large IC engines results in a 2.8 g/ bhp hr limit. Draft   Do not cite, quote or distribute 98 Comment: In their letter of October 25, 2002, INGAA commented that the additional data we collected includes data on 27 lean burn engines and the data indicate that the average retrofit LEC technology level is 2.7 g/ bhp hr for 2

stroke engines, which represent the bulk of the engine horsepower in the NOx SIP Call area. In addition, INGAA commented that the data reported on the IC engines retrofit with LEC have a number of problems, including scarcity of before and after tests on the same engine, and the absence of data on load or other operating conditions of the tested engines. The INGAA also commented that the vendor references we cited indicate that the retrofit LEC technology is intended to result in emissions to meet a 3 g/ bhp hr limit.

Response: We agree that test data cited by INGAA and the vendor estimates indicate that the average retrofit LEC technology level is in the 2.7 to 3.0 g/ bhp hr range. We also note that these comments are fairly consistent with a November 20, 2000 letter to the OTC from two pipeline companies which recommended a limit of no less than 3.0 g/ bhp hr, with an alternative standard of no more than 80 percent reduction. This range is also consistent with the available test data for large engines in the NOx SIP Call area which indicates an average value of 2.8 g/ bhp hr. Draft   Do not cite, quote or distribute 99 As INGAA points out, there is some uncertainty in the test data due, for example, to lack of data on operating load in some cases. In addition, there is some uncertainty because of the lack of data for all engine models. Due to this uncertainty, we believe it is appropriate to consider a minor adjustment to the control level suggested by the test data. The difference between selecting a 2.8 value ( suggested primarily by the test data) or a 3.0 value ( suggested by some pipeline companies and vendor comments)

for the controlled emission rate is very small, only a 1 percent difference. That is, the two values result in either an 82 percent or 83 percent control level, assuming a 16.8 g/ bhp hr uncontrolled value. Thus, while our analysis of the test data indicates a 2.8 value is reasonable, in view of the recommended 3.0 level from some industry and vendor comments, and considering the uncertainties in the data and the small difference in the resultant control level, we believe it is appropriate to select the upper range of the control levels proposed, namely 3.0 g/ bhp hr.

( 3) Level of NOx control to assume for budget calculation.

Comment: In the proposed rule we invited comment on how many of the large natural gas fired IC engines are from lean burn operation and how many are from rich burn. The INGAA Draft   Do not cite, quote or distribute 100 commented that 156 of the 168 large engines listed in the NOx SIP Call Inventory that have Standard Industrial Classification codes associated with the natural gas transmission industry are lean burn models, with one exception. For the purposes of calculating the IC engine portion of the NOx SIP Call State budgets, INGAA recommended that we should assume that all the large natural gas fired stationary engines in the inventory are lean burn. Comments from the State of Indiana indicated there are no large,

rich burn engines in the State.

Response: As pointed out by the commenters, the vast majority of large IC engines in the NOx SIP Call inventory are natural gas fired lean burn engines. Furthermore, the emission inventory does not contain sufficient detail to determine exactly which engines are lean burn and which are not. For these reasons, we agree with the comment that it is reasonable to assume that all the large natural gas stationary engines in the inventory are lean burn for the purposes of calculating the IC engine portion of the NOx SIP Call State budgets.

Comment: As discussed above, we received comments on the uncontrolled and controlled levels for natural gas fired engines. Several commenters recommended no more than 70 percent reduction, based primarily on permit data. One Draft   Do not cite, quote or distribute 101 State recommended 90 percent reduction.

Response: The percent reduction determination is based primarily on two factors   the uncontrolled and controlled levels   which are discussed above. We reviewed information submitted by commenters and collected additional data in response to concerns raised by commenters. Considering all of the available data, we have determined that the appropriate uncontrolled and controlled values are 16.8 and 3.0, respectively. As a result, we believe that application of highly cost effective controls on large natural gas fired IC engines will achieve, on average, an 82 percent reduction. Therefore, 82 percent is used for purposes of calculating this portion of the NOx SIP Call budget.

b. Flexibility/ Averaging.

Comment: Several commenters noted that the response of IC engines to retrofit NOx controls is highly variable and that the average NOx reduction used to calculate the NOx SIP Call budgets is not necessarily the level that all large engines can achieve. Because of this variability, these commenters suggest that State air agencies should assign NOx reductions to the owners or operators of IC engines, but not attempt a uniform definition of the required control technology, or specification of a single compliance limit. The commenters suggest that we include language in the final rule stating Draft   Do not cite, quote or distribute 102 that we recommend, and will approve, SIPs which provide that owners or operators of large engines in the NOx SIP Call inventory develop company specific compliance plans to demonstrate achievement of NOx reductions. In addition to describing the standards for emissions reductions averaging in the final rule, commenters suggested that we issue a guidance letter to the States urging them to provide flexibility for IC engines and explaining how to do that.

The industry lists a number of advantages to the company compliance plan approach to meeting the engine NOx reductions in the NOx SIP Call Rule:

° Engine owners and operators would accept enforceable and verifiable measures to control engines to meet assigned NOx SIP Call reductions.

° Based on the company compliance plans, States would be able to clearly demonstrate to us their compliance with Phase II of the NOx SIP Call.

° The EPA, States, and regulated companies would not have to work through the technical confusion of definitions of lean burn and rich burn engines,

and whether individual engines could in fact achieve certain control levels with a prescribed control technology.

° Compliance with NOx SIP Call requirements could be Draft   Do not cite, quote or distribute 33 August 22, 2002 memo from Lydia Wegman to EPA Regional Air Directors providing guidance on issues related to stationary IC engines and the NOx SIP Call ( Docket No. OAR 2001 0008 ( Legacy Docket No. A 96 56), Item No. XII C 115).

103 achieved with minimum impacts on cost, natural gas capacity, and operational reliability.

One pipeline company stated that we should encourage States implementing the engine portion of the NOx SIP Call to focus primarily on the population of large engines which emitted more than 1 ton per day during the 1995 ozone season and which formed the basis for our calculation of the desired emissions reductions. Retrofitting this population of engines is more feasible and is the most cost effective method for achieving reductions due to economies achieved by controlling larger sources.

Response: We addressed this issue in a guidance memorandum dated August 22, 2002. As discussed in the reference memorandum, 33 where States choose to regulate large IC engines, we encourage the States to allow owners and operators of large IC engines the flexibility to achieve the NOx tons/ season reductions by selecting from among a variety of technologies or a combination of technologies applied to various sizes and types of IC engines. Flexibility would be helpful as companies take into account that individual engines or engine models may respond differently to control Draft   Do not cite, quote or distribute 104 equipment. That is, while certain controls are known to have a specific average control effectiveness for an engine population, some individual engines that install the controls would be expected to be above and some below that average control level, simply because it is an average.

Although the issue of flexibility does not affect the setting of the NOx SIP Call budget, it is an important issue as States take steps to meet their NOx SIP Call requirements.

During the SIP development process, the States may establish a NOx tons/ season emissions decrease target for individual companies and then provide the companies with the opportunity to develop a plan that would achieve the needed emissions reductions. The companies may select from a variety of control measures to apply at their various emission units in the State, or portion of the State,

affected under the NOx SIP Call. These control measures would be adopted as part of the SIP and must yield enforceable and demonstrable reductions equal to the NOx tons/ season reductions required by the State. What is important from our perspective is that the State, through a SIP revision, demonstrate that all the control measures contained in the SIP are collectively adequate to provide for compliance with the State's NOx budget during the 2007 Draft   Do not cite, quote or distribute 105 ozone season.

c. New Source Review ( NSR) Exclusion.

Comment: Some commenters stated that the final rule should provide an exemption from NSR regulations for IC engines that install NOx controls for compliance with the NOx SIP Call. According to the commenters, installation of the required emission controls will likely result in increases in emissions of carbon monoxide ( CO) and/ or volatile organic compounds ( VOC); the resulting emission increases could exceed the " significant" levels for carbon monoxideCO or VOC, thereby subjecting those facilities to either prevention of significant deterioration ( PSD) or nonattainment NSR permit requirements; and, this would increase the compliance costs. Pipeline industry comments request that we expressly state in our final remand response that installing controls on IC engines to meet NOx SIP Call requirements will not trigger NSR for NOx under the "

actualto potential" test. Commenters also request that we state that installing retrofit controls is an " environmentally beneficial" action that qualifies for a NSR exclusion for any collateral increases of other criteria pollutants.

Response: As discussed in the earlier referenced Draft   Do not cite, quote or distribute 34 August 22, 2002 memo from Lydia Wegman to EPA Regional Air Directors providing guidance on issues related to stationary IC engines and the NOx SIP Call ( Docket No. OAR 2001 0008 ( Legacy Docket No. A 96 56), Item No. XII C 115).

35 In the Federal Register on December 31, 2002, EPA codified/ finalized the Pollution Prevention Project exclusion. In Table 2, Environmentally Beneficial Pollution Control Projects, LEC for IC engines is mentioned. However, for the present time, the regulatory changes generally only affect States with delegation authority to implement the Federal PSD program which became effective on March 3, 2003. For States continuing to implement their existing programs for another 2 to 3 years, the August 22, 2002 guidance memo mentioned above, is appropriate.

106 memorandum, 34, where sources choose to install combustion modification technology to reduce emissions of NOx at natural gas fired lean burn IC engines, we believe this action should be considered by permitting authorities for exclusion from major NSR as a pollution control project.

Further, the memo indicates that, unless information regarding a specific case indicates otherwise, installation of combustion modification technology for the purpose of reducing NOx emissions at natural gas fired lean burn IC engines can be presumed, by its nature, to be environmentally beneficial. We recently stated our intent to modify the " actual to potential" test. 35 In most cases,

we believe that LEC retrofit technology will not increase emissions of CO or VOC to the extent that NSR is triggered;

in many cases, emissions of CO and VOC will decrease with the installation of LEC technology ( see RTC document for Draft   Do not cite, quote or distribute 107 details). Thus, we believe that the permit process will not hamper efforts to install controls.

d. Early Reductions.

Comments: Industry comments recommend that we provide specific guidance in the final rule that directs States to recognize emissions reductions that companies have made since 1995 and that companies should be allowed credit for emissions reductions achieved since 1995 for determining compliance with their portion of the States' emissions reductions required to meet the emissions budgets.

Response: We addressed this issue in the above mentioned guidance memorandum. As discussed in the memo, we agree that creditable reductions with respect to the NOx SIP Call may include emission controls in place during or prior to 1995, as well as after 1995 for the large engines. In addition, States generally may use emissions reductions achieved after 1995 at the smaller engines as part of their NOx SIP Call budget demonstration.

e. Presumptive Technology.

Comment: Because of the variability of gas pipeline engines in the NOx SIP Call area, industry commenters suggest that State air agencies should assign NOx reductions to the owners or operators of IC engines, but not attempt a uniform definition of the required control technology, or Draft   Do not cite, quote or distribute 108 specification of a single compliance limit. There is significant variability both in the pre controlled emission levels of lean burn engines and in the response of any particular engine to the retrofit installation of LEC technology.

Response: As suggested, we have dropped from the final rulemaking the definition of LEC retrofit technology and the presumption of NOx reduction effectiveness. The definition and presumption are not necessary to establish the NOx budget. Nevertheless, we believe that, on average, LEC technology achieves an 82 percent reduction from uncontrolled emissions.

f. Monitoring.

Comment: Industry comments recommended that we should specify in the final rule the types of monitoring that will be acceptable.

Response: We addressed this issue in the August 22, 2002 guidance memorandum. As discussed in the memo, acceptable monitoring is not limited to those monitoring methods such as continuous or predictive emissions measurement systems that rely on automated data collection from instruments.

Non automated monitoring may provide a reasonable assurance of compliance for IC engines provided such periodic monitoring is sufficient to yield reliable data for the Draft   Do not cite, quote or distribute 109 relevant time periods determined by the emission standard.

g. Emission Factors for 2 and 4 Stroke Engines.

Comment: Some commenters asked us to use separate emission factors for 2 and 4 stroke engines.

Response: As described above, we examined " uncontrolled"

emissions from 2 and 4 stroke engines separately and concluded that the data support the 16.8 value we proposed.

We also examined the available " controlled" data separately for 2 and 4 stroke engines. Test data for the large IC engines in the NOx SIP Call area indicate controlled levels of 2.3 and 2.5, respectively, for the 2 and 4 stroke engines.

Assuming 85 percent of the engines in the NOx SIP Call area are 2 stroke, the weighted average of the 2.3 and 2.5 values is 2.3. Thus, because the 2 stroke engines dominate the NOx SIP Call inventory and the controlled value for the 4 stroke engines is nearly identical, there is no benefit from using separate emission factors. Furthermore, our emission inventory is not detailed enough to identify which engines are 2 or 4 stroke engines; thus, we need to use an average value to represent the combined population of large,

leanburn engines. We believe the difference between the two values is relatively small, there is a great deal of overlap, some key industry reports also use a single value, Draft   Do not cite, quote or distribute 110 the available data for 2 and 4 stroke engines support the value we proposed, control techniques are the same, and we have already subdivided the category of IC engines. For these reasons, we have chosen not to further subdivide the IC engines category.

C. What is Our Response to the Court Decision on Georgia and Missouri?

In today's final action, we are finalizing our inclusion of only certain portions of Georgia and Missouri in the NOx SIP Call and revising their statewide budgets to reflect our inclusion of only sources in the fine grid parts of both States.

As stated in the final NOx SIP Call Rule, air pollution travels across county and State lines and it is essential for State governments and air pollution control agencies to cooperate to solve the problem. Ozone transport is a regional problem and we believe that NOx emissions reductions across the region in amounts achievable by costeffective controls is a reasonable step to take to mitigate ozone nonattainment in downwind States ( 63 FR 57362). These emissions reductions, in combination with other measures,

will enable attainment and maintenance of the 1 hour ozone Draft   Do not cite, quote or distribute 36 OTAG Policy Paper approved by the Policy Group on December 4, 1995.

111 NAAQs in the OTAG region. 36 Since the problem is a regional one, we believe that all States in the NOx SIP Call area must cooperate to solve the problem.

By way of background, we took final action on October 27, 1998, in the NOx SIP Call Rule, to prohibit those amounts of NOx emissions which significantly contribute to downwind nonattainment. See, NOx SIP Call Rule, 63 FR 57356. We determined the amount of emissions that significantly contribute to downwind nonattainment by evaluating:

( 1) the overall nature of the ozone problem ( i. e.

" collective contribution"); ( 2) the extent of the downwind nonattainment problems to which the upwind State's emissions are linked, including the ambient impact of controls required under the CAA or otherwise implemented in the downwind areas; ( 3) the ambient impact of the emissions from the upwind State's sources on the downwind nonattainment problems; and ( 4) the availability of highly cost  effective control measures for upwind emissions. [( 63 FR 57376 (, October 27,

1998)].

As part of our analyses of the air quality factors we Draft   Do not cite, quote or distribute 37 In addition to these three factors, OTAG considered three other factors in establishing the geographic resolution, overall size, and the extent of the fine grid. These other factors dealt with the computer limitations and the resolution of available model inputs.

112 considered the OTAG modeling and our State specific modeling. Id. at 57384.

In its modeling, OTAG used grids drawn across most of the eastern half of the United States. The " fine grid" has grid cells of approximately 12 kilometers on each side ( 144 square kilometers). The " coarse grid" extends beyond the perimeter of the fine grid and has cells with 36 kilometer resolution. The fine grid includes the area encompassed by a box with the following geographic coordinates as shown in Figure 1, below: Southwest Corner: 92 degrees West longitude, 32 degrees North latitude; Northeast Corner:

69.5 degrees West longitude, 44 degrees North latitude ( OTAG Final Report, chapter 2). The OTAG could not include the entire Eastern U. S. within the fine grid because of computer hardware constraints.

It is important to note that there were three key factors directly related to air quality which OTAG considered in determining the location of the fine gridcoarse grid line. 37 ( OTAG Technical Supporting Document,

chapter 2, pg. 6; also available at the following website: Draft   Do not cite, quote or distribute 38 The OTAG recommendation on Major Modeling/ Air Quality Conclusions approved by the Policy Group, June 3, 1997 ( 62 FR 60318, appendix B, November 7, 1997).

113 www. epa. gov/ ttn/ naaqs/ ozone/ rto/ otag/ finalrpt/).

Specifically, the fine grid coarse grid line was drawn to:

( 1) include within the fine grid as many of the 1 hour ozone nonattainment problem areas as possible and still stay within the computer and model run time constraints, ( 2)

avoid dividing any individual major urban area between the fine grid and coarse grid, and ( 3) be located along an area of relatively low emissions density. As a result, the fine grid coarse grid line did not track State boundaries, and Missouri and Georgia were among several States that were split between the fine and coarse grids. Eastern Missouri and northern Georgia were in the fine grid while western Missouri and southern Georgia were in the coarse grid.

The analysis OTAG conducted found that the emission controls they examined, when modeled in the entire coarse grid ( i. e., all States and portions of States in the OTAG region that are in the coarse grid) had little impact on high 1 hour ozone levels in the downwind ozone problem areas of the fine grid. 38 The OTAG also concluded from its modeling that the closer an upwind area is to the downwind area, the greater the benefits in the downwind area from controls in the upwind area. Draft   Do not cite, quote or distribute 39 The 2007 Base Case includes all control measures required by the CAA.

114 Examining the 2007 Base Case39 NOx emissions for Georgia indicates that the amount of NOx emissions per square mile in the fine grid portion of the State is over 60 percent greater than in the coarse grid part. In Missouri,

the amount of NOx emissions per square mile in the fine grid portion of the State is more than 100 percent greater ( i. e.,

more than double) than in the coarse grid part. The OTAG concluded from its modeling that the closer an upwind area is to the downwind area, the greater the benefits in the downwind area from controls in the upwind area.

A number of parties, including certain States as well as industry and labor groups challenged the NOx SIP Call Rule. Specifically, Georgia and Missouri industry petitioners claimed that our record supported inclusion of only eastern Missouri and northern Georgia as contributing significantly to downwind nonattainment. The D. C. Circuit Court upheld our finding of significant contribution for almost all jurisdictions covered by the NOx SIP Call, but vacated and remanded our inclusion of Georgia and Missouri.

Michigan v. EPA, 213 F. 3d 663 ( D. C. Cir. 2000), cert.

denied, 121 S. Ct. 1225 ( 2001)( Michigan). The Court found that the NOx budgets for these States " not only encompass the whole state but are calculated on the basis of Draft   Do not cite, quote or distribute 115 hypothesized cutbacks from areas that have not been shown to have made significant contributions." Id. at 684 ( emphasis in original). The Court also found that " EPA must first establish that there is a measurable contribution" from the coarse grid portion of the State before holding the coarse grid portion of the State responsible for the significant contribution of downwind ozone nonattainment in another state. Id. at 683 84 ( emphasis in original).

Subsequently, we made revisions to the NOx SIP Call Rule emissions budgets in the Technical Amendments Rulemakings [( 64 FR 26298 (, May 14, 1999); ( 65 FR 11222 (,

March 2, 2000)]. A group of Missouri Utilities and the City of Independence, Missouri challenged our budget for the State of Missouri and requested the Court to vacate the entire budget under both the 1 hour and 8 hour ozone standards. In its decision, the Court found " it prudent to vacate and remand the TAs [ technical amendments] insofar as they include[ d] a budget for Missouri under any ozone standard." Appalachian Power Company v. EPA, 251 F. 3d 1026, 1041 ( 2001). The Court also found that "[ w] here the agency's own data inculpate part of a state and not another,

EPA should honor the resulting findings." Id. at 1040.

In response to the Court's decisions, we issued the February 22, 2002 rule proposing to include only fine grid Draft   Do not cite, quote or distribute 116 parts of Georgia and Missouri in the NOx SIP Call. We explained that the Court in Michigan did not call into question our " proposition that the fine grid portion of each State should be considered to make a significant contribution downwind." ( 67 FR 8413).

We stated that based on OTAG's modeling and recommendations, the technical support documents for the NOx SIP Call rulemaking, and emissions data, we believed that emissions in the fine grid parts of Georgia and Missouri comprise a measurable or material portion of the entire State's significant contribution to downwind nonattainment.

In addition, we explained that we had performed State by

State modeling for Georgia and Missouri as part of the final NOx SIP Call rulemaking. The results of this modeling showed that emissions in both Georgia and Missouri make a significant contribution to nonattainment in other States.

Moreover, we explained that the Court pointed out that the fine grid portion of each State lies closer to downwind nonattainment areas. Michigan v. EPA, 213 F. 3d at 683.

We further explained that for purposes of determining budgets for the fine grid portion, we believed that OTAG modeling should be used with an adjustment for counties that straddle the line separating the fine grid and coarse grid.

We also explained that we would base our overall NOx Draft   Do not cite, quote or distribute 117 emissions budgets on all counties which lie wholly contained in the fine grid, as a result of the difficulties and uncertainties associated with accurately dividing the fine and coarse grid for individual counties. Counties that straddle the fine grid coarse grid line or which are completely within the coarse grid would be excluded from the budget calculations for Georgia and Missouri. As a result,

we proposed to revise the NOx budgets for Georgia and Missouri to include only the fine grid portions of these States.

In response to our proposal, several commenters asserted that our inclusion of the fine grid portions of the States of Georgia and Missouri was not supported by reliable data in light of the Court's ruling in Michigan and requested additional air quality modeling for these portions. A couple of commenters submitted air quality modeling and one commenter requested reconsideration of our inclusion of sources that lie " just inside the fine grid."

Other commenters argued that no NOx SIP Call exists for the States of Georgia and Missouri in light of the Court's holdings in Michigan and Appalachian Power ( Technical Amendments Case). They further argued that the Agency must make independent findings of significant contribution for both eastern Missouri and northern Georgia, respectively. Draft   Do not cite, quote or distribute 118 One commenter also contended that we could not base our findings on existing data but must consider new circumstances and any changes in air quality since promulgation of the NOx SIP Call Rule. Another commenter requested that we not exclude sources in any county that partially lies within the coarse grid area in the affected States.

Under today's final rulemaking, we are finalizing our proposal to include the fine grid portions of Georgia and Missouri as contributing significantly to downwind nonattainment. We believe this is consistent with the Court's pronouncements in Michigan. Specifically, the Court found that "[ t] he fine grid modeling of parts of Missouri and Georgia showed emissions in the aggregate meeting the EPA's threshold contribution` contribution' criteria."

Michigan, 213 F. 3d at 683 ( emphasis in original). The Court also found that it was " no mere techno fortuity that the fine grid included enough of Missouri to include the city of St. Louis and enough of Georgia to include Atlanta:

[ because] the fine grid portions of both states are closest to other nonattainment areas, such as Chicago and Birmingham, and generally higher ozone density." Id.

We see no reason to revise the existing determination that sources in the fine grid parts of Georgia and Missouri Draft   Do not cite, quote or distribute 119 contribute significantly to downwind nonattainment. As explained in our proposal, the basis for our determination continues to be: ( 1) the results of our State by State modeling; ( 2) the relatively high amount of NOx emissions per square mile in the fine grid portions of each State; and ( 3) the close locationscloseness of the fine grid portions of each State to downwind nonattainment areas compared to the coarse grid portions ( 67 FR 8414).

Additionally, we note that Georgia and Missouri industry petitioners maintained, as we believe, that there was only record support for inclusion of emissions from the eastern half of Missouri and the northern two thirds of Georgia as contributing to downwind ozone problems. As the Court stated, "[ a] ccordingly, they say the NOx Budget for Missouri and Georgia should be based solely on those emissions." Michigan 213 F. 3d at 684.

We have also evaluated the modeling submitted by one commenters and we find that this modeling does not refute our conclusion that sources in the fine grid portions of Georgia and Missouri contribute significantly to downwind nonattainment, as discussed below.

Accordingly, consistent with the Court's finding in Michigan, we have revised the NOx emissions budgets for Georgia and Missouri to include only the fine grid portions Draft   Do not cite, quote or distribute 120 of these States. The counties that are included in the calculation of NOx budgets for each of these States are listed in Table 1.

Table 1. Fine Grid Counties in Georgia and Missouri Georgia Baldwin Co Effingham Co Jefferson Co Putnam Co Banks Co Elbert Co Jenkins Co Rabun Co Barrow Co Emanuel Co Johnson Co Richmond Co Bartow Co Evans Co Jones Co Rockdale Co Bibb Co Fannin Co Lamar Co Schley Co Bleckley Co Fayette Co Laurens Co Screven Co Bulloch Co Floyd Co Lincoln Co Spalding Co Burke Co Forsyth Co Lumpkin Co Stephens Co Butts Co Franklin Co McDuffie Co Talbot Co Candler Co Fulton Co Macon Co Taliaferro Co Carroll Co Gilmer Co Madison Co Taylor Co Catoosa Co Glascock Co Marion Co Towns Co Chattahoochee Co Gordon Co Meriwether Co Treutlen Co Chattooga Co Greene Co Monroe Co Troup Co Cherokee Co Gwinnett Co Morgan Co Twiggs Co Clarke Co Habersham Co Murray Co Union Co Clayton Co Hall Co Muscogee Co Upson Co Cobb Co Hancock Co Newton Co Walker Co Columbia Co Haralson Co Oconee Co Walton Co Coweta Co Harris Co Oglethorpe Co Warren Co Crawford Co Hart Co Paulding Co Washington Co Dade Co Heard Co Peach Co White Co Dawson Co Henry Co Pickens Co Whitfield Co De Kalb Co Houston Co Pike Co Wilkes Co Dooly Co Jackson Co Polk Co Wilkinson Co Douglas Co Jasper Co Pulaski Co Missouri Bollinger Co Iron Co Oregon Co St. Francois Co Butler Co Jefferson Co Pemiscot Co St. Louis Co Cape Girardeau Co Lewis Co Perry Co St. Louis City Carter Co Lincoln Co Pike Co Scott Co Clark Co Madison Co Ralls Co Shannon Co Crawford Co Marion Co Reynolds Co Stoddard Co Dent Co Mississippi Co Ripley Co Warren Co Dunklin Co Montgomery Co St. Charles Co Washington Co Draft   Do not cite, quote or distribute 121 Franklin Co New Madrid Co St. Genevieve Co Wayne Co Gasconade Co We are not making a finding today as to whether sources in the coarse grid portions of Georgia and/ or Missouri make a measurable or material part of the significant contribution of each of these States,

respectively. In addition, apart from our findings relating to the NOx SIP Call, a State may, of course, assess the in

State impacts of NOx emissions from its coarse grid area,

and impose additional NOx reductions, beyond the NOx SIP Call requirements in the fine grid, as necessary to demonstrate attainment or maintenance of the ozone NAAQS in the State.

Comment: Several commenters supported our inclusion of the fine grid portions of Missouri and Georgia. One commenter requested that we not exclude sources within any county that partially lies within the coarse grid area in the affected States.

Response: Today's action is in response to the court's decision that vacated our inclusion of the entire States of Georgia and Missouri. Michigan v. EPA, 213 F. 3d 663. ( D. C.

Cir. 2000), cert. denied, 121 S. Ct. 1225 ( 2001)( Michigan).

" EPA must first establish that there is a measurable contribution" from the coarse grid portion of the State before holding the coarse grid portion responsible for the Draft   Do not cite, quote or distribute 122 significant contribution of downwind ozone nonattainment in another state." Id. At 683 84 ( emphasis in original).

As explained in our February 22, 2002 proposal,

" because of difficulties and uncertainties with accurately dividing emissions between the fine and coarse grid of individual counties for the purpose of setting overall NOx emissions budgets, we believe that the calculation of the emissions budgets should be based on all counties which are wholly contained within the fine grid." 67 FR 8415.

In today's action we are finalizing our proposal because at this time we have not accurately determined the emissions attributed to either the fine grid or coarse grid portions of such counties( 67 FR 8415). We believe this is also consistent with the Court's ruling. Thus, we have now recalculatedare finalizing the budgets for Georgia and Missouri to include only those counties that lie wholly within the fine grid portions of both States as described above.

Comment: One commenter requested the reconsideration of our inclusion of sources that are " just inside the fine grid."

This commenter based its request on modeling showing that sources in Georgia south of 32.67 degrees latitude do not significantly contribute to nonattainment ozone areas in Draft   Do not cite, quote or distribute 123 downwind States.

Response: We have evaluated the modeling submitted by this commenter and found that the modeling does not refute the overall conclusions we have drawn concerning the impacts of NOx emissions in the relevant geographic areas. The commenter quantified the contribution from those emissions in Georgia south of 32.67 degrees latitude ( i. e., southern Georgia) by modeling the four OTAG episodes with emissions in southern Georgia removed ( i. e., zero out). The results of this modeling, as presented by the commenter, suggest that emissions in southern Georgia contribute less than 2 parts per billion ( ppb) to the peak daily 1 hour ozone in 1

hour nonattainment areas outside of Georgia in each of the four episodes. In view of these results, the commenter contends that the contribution from southern Georgia to all downwind nonattainment areas is not significant since the contribution is less than the 2 ppb screening criteria used by EPA in the NOx SIP Call to identify those upwind Stateto downwind nonattainment area linkages that were clearly not significant. However, the commenter misinterpreted the definition of EPA's 2 ppb screening criteria by limiting the analysis of contribution to just the episode peak concentration in the downwind areas. By doing so, the contractor did not consider or present any data to evaluate Draft   Do not cite, quote or distribute 124 the contribution from southern Georgia to other ozone exceedances ( i. e., less than the peak value byut exceeding the NAAQS) predicted in each downwind area. For example,

southern Georgia may not impact the predicted episode peak for the 1 hour ozone standard in Birmingham by 2 ppb, but southern Georgia could have contributed at least 2 ppb to one or more of the other 88 exceedances in Birmingham.

Unfortunately, the commenter did not provide any data to permit an examination of the contribution fromof emissions from southern Georgia to all exceedances in downwind nonattainment areas. Thus, the comment that southern Georgia does not significantly contribute to downwind nonattainment because thethey did not examine all contributions are less than 2 ppb is not fully supported by the data presented by the commenter. above 2 ppb.

Thus, to the extent that thise source iss are modeled by the commenter in a county that falls within the fine grid part of Georgia, we do not believe we should reconsider its inclusion in the NOx SIP Call.

Comment: Several commenters stated that our inclusion of portions of the State of Georgia was not supported by reliable data and sound science especially in light of Michigan, " that remanded and vacated in its entirety [ the inclusion of whole states of Georgia and Missouri]," due to Draft   Do not cite, quote or distribute 125 " EPA's unsupportable determination of significant contribution." Several commenters also stated that we had failed to provide data to support the inclusion of portions of the State of Georgia that are within the fine grid.

Another commenter argued that we had failed to provide information to support inclusion of affected sources in Georgia.

Response: In Michigan, the D. C. Circuit Court held that "[ t] he fine grid modeling of parts of Missouri and Georgia showed emissions in the aggregate meeting the EPA's threshold contribution criteria." Michigan, 213 F. 3d at 683 ( emphasis in original). The Court noted that " EPA's explanation and technique make clear that emissions from the fine grid areas may have been the sole source of the finding." Id.

The Court also found that it was " no mere technofortuity that the fine grid included enough of Missouri to include the city of St. Louis and enough of Georgia to include Atlanta: [ because] the[ se] fine grid portions of both states are closest to other nonattainment areas, such as Chicago and Birmingham, and generally higher ozone density." Id. However, the Court vacated and remanded the NOx SIP Call budgets for the States of Georgia and Missouri finding that the budgets " not only encompass the whole state Draft   Do not cite, quote or distribute 126 but are calculated on the basis of hypothesized cutbacks from areas that have not been shown to have made significant contributions." Id at 684. ( emphasis in original). The Court further held that " EPA must first establish that there is a measurable contribution" from the coarse grid portion of the State before holding the coarse grid portion of the State responsible for the significant contribution of downwind ozone nonattainment in another sState. Id. In Appalachian Power Company v. EPA, 251 F. 3d 1026, 1040 1 ( 2001), the Court found that " insofar as the TAs [ technical amendments] include a statewide Missouri emission budget they are unlawful under Michigan."

Thus, the Court did not call into question the proposition that the fine grid portions of Georgia and Missouri should be considered as making a significant contribution to downwind nonattainment. We also note that Georgia and Missouri industry petitioners maintained that,

as we believe, there was only record support for inclusion of emissions from the eastern half of Missouri and the northern two thirds of Georgia as contributing to downwind ozone problems. Michigan, 213 F. 3d at 681.

In addition, in the NOx SIP Call Rule, we found that "[ s] ources that are closer to the nonattainment area tend to have much larger effects on the air quality than sources Draft   Do not cite, quote or distribute 127 that are far away." ( 63 FR 25919.) Further, OTAG's technical findings and recommendations concluded that areas located in the fine grid should receive additional controls because they contribute to ozone in other areas within the fine grid.

Today's rulemaking finalizes our revision of the budgets for Georgia and Missouri to reflect the Court's pronouncements in Michigan. This is also consistent with OTAG's recommendations and findings. We have revised neither our existing determination nor our bases for the determination that sources in the fine grid portion of Georgia and Missouri are contributing significantly to downwind nonattainment. We are revising the NOx budgets for Georgia and Missouri to reflect the inclusion of only the sources that are within the fine grid portions of both States. Accordingly, we also continue to rely on the Technical Support Document and Notice of Data Availability which are the underlying documents for the NOx SIP Call Rule.

Comment: One commenter argued that the Court vacated our determination of significant contribution for all of Missouri in Michigan, and therefore, we no longer have a basis for including any portion of Missouri in the NOx SIP Call. The commenter also argued that we made no significant Draft   Do not cite, quote or distribute 128 contribution finding for eastern Missouri but rather based our findings on emissions from the whole State.

Response: We disagree with the comment. As stated elsewhere in this rule, the Court did not question our findings of significant contribution forwith respect to the fine grid parts of Georgia and Missouri. , the Court found that "[ T] the fine grid modeling of parts of Missouri and Georgia showed emissions in the aggregate meeting the EPA's threshold contribution criteria." Michigan, 213 F. 3d. aAt 683. We also note that Georgia and Missouri industry petitioners maintained that there was only record support for inclusion of emissions from the eastern half of Missouri and the northern two thirds of Georgia as contributing to downwind ozone problems. Id., at 681. The OTAG's recommendations and findings concluded that areas located in the fine grid should receive additional controls because they contribute to ozone in other areas within the fine grid. In addition, our modeling showed that emissions in both Georgia and Missouri make a significant contribution to nonattainment in other areas. Therefore, we believe there is record support for inclusion of eastern Missouri.

Comment: One commenter argued that as a result of the vacatur in Michigan, we have to justify the inclusion of eastern Missouri in the NOx SIP Call taking into Draft   Do not cite, quote or distribute 129 consideration facts in existence at the time of our proposal ( February 22, 2002, 67 FR 8395).

Response: We disagree. As stated earlier, the Court did not question our findings of significant contribution forfound that the modeling showed that emissions from the fine grid portions of the States of Georgia and Missouri met EPA's " threshold ` contribution' criteria." The Court also let stand OTAG's modeling analyses ( except with respect to Wisconsin). Thus, the inclusion of eastern Missouri accords with the Court pronouncements on the fine grid/ coarse grid.

In today's rulemaking, we see no reason to revise the existing determination that sources in the fine grid parts of Missouri contribute significantly to nonattainment downwind. The basis for this determination continues to be:

( 1) the results of our State by State modeling; ( 2) the relatively high amount of NOx emissions per square mile in the fine grid portions of the State; and ( 3) the close locationscloseness of the fine grid portions of the State to downwind nonattainment areas compared to the coarse grid part.

Comment: One commenter stated that it was erroneous to continue using data that was 4 years old as our basis for the inclusion of eastern Missouri in the NOx SIP Call in light of data showing that areas receiving measurable Draft   Do not cite, quote or distribute 130 contributions from Missouri sources are now in attainment of the 1 hour ozone standards.

Response: We disagree with the comment that downwind ozone nonattainment areas have achieved attainment of the 1 hour ozone standards. More specifically, Chicago has not yet attained the 1 hour ozone standard. Chicago's attainment demonstration relies, in part, on implementation of Missouri's statewide NOx rule, approved by EPA into the SIP.

The NOX SIP Call reductions in Missouri are needed for Chicago to attain/ maintain the 1 hour standard. The reductions will also help Chicago and other areas attain the 8 hour ozone standard.

Although the attainment plan was approved, we believe it is important to point out that there are inherent uncertainties in the plan, including hourly emission estimates and emissions growth projections. Further,

without the NOx SIP Call, Missouri may come under increased pressure to relax the existing State rule, which could jeopardize attainment in Chicago. Additionally, the SIPapproved State rule has not yet been implemented and was, in fact, recently revised by the State.

Additional emissions reductions due to the NOx SIP Call would help attain and maintain the 8 hr ozone and PM fine standards, improve visibility and reduce deposition of Draft   Do not cite, quote or distribute 131 nitrogen. Missouri was found to significantly contribute to nonattainment of the 8 hour ozone standard in eight downwind States ( IL, IN, KY, MI, OH, PA, TN & WI). The reductions are highly cost effectivecost effective and would also help offset emissions from a number of large sources locating upwind of St. Louis and avoid very costly local controls in the future.

In general, we believe an agency should not revisit an otherwise sound rulemaking just due to the passage of time leading to changed circumstances, because circumstances always change. Specifically, we disagree that a new emissions inventory is necessary that takes into account Missouri's statewide NOx rule and other post 1998 CAA rules.

Because SIPs are constantly changing, it is impractical to revise emission inventories and modeling analyses each time changes are made. For example, the NOx limits the commenter cites have since been revised by the State and are yet to be approved by EPA.

Further, completing the NOx SIP Call in Missouri is an equitable approach. It would be inequitable to use 2003 air quality analysis for Missouri but to hold other NOx SIP Call States to the 1998 analysis. It should also be noted that we intend to review the NOx SIP Call Rule and will make adjustments if necessary ( 63 FR 57428). Draft   Do not cite, quote or distribute 132 This program is the single most important measure to reduce interstate pollution in the short term. Reductions of NOx emissions from the program will enhance the protection of public health for over 100 million people in the eastern half of the United States  including people in Missouri. It is a centerpiece of the clean air plans for many cities, including the Chicago area.

Comments: Another commenter stated that the current sState of Missouri control regulations would achieve greater NOx emissions and greater improvements than the NOx SIP Call.

Response: We disagree. Missouri adopted and, in December 2000, we approved a statewide NOx rule which requires emissions reductions in the eastern third of the State and lesser reductions in the remainder of the State for large EGUs. While we approved this rule because it helped address the ozone nonattainment issue in St Louis, we did not find that this rule addressed the significant transport of NOx to other areas that we had identified in the NOx SIP Call.

Revisions to the statewide NOx rule were adopted on April 24, 2003 and may bewere submitted as a SIP revision sometime after their effective date of August 30on September 18,

2003.

Both the SIP approved statewide NOx rule and the recent revisions to the rule adopted by the Statesubmitted to EPA Draft   Do not cite, quote or distribute 133 would achieve less NOx emissions reductions than implementation of the NOx SIP Call. Missouri's current and proposed revised NOx rules are less stringent than the NOx SIP Call requirements. There are greaterThe emissions reductions under the NOx SIP Call ( are greater by about 20 percent statewide and 40 percent in the fine grid compared to the SIP approved Missouri rule). The NOx SIP Call also offers the advantages of a cap and trade program, including certainty of emissions reductions; the State rules have no emissions cap. While the current State rule and the SIP revisions may accomplish reductions similar to those under the NOx SIP Call in the short term, without an emissions cap there is no assurance that the required reductions will continue in the long term.

Reductions are more effective in preventing interstate transport to key downwind areas under the NOx SIP Call as they must occur in the eastern part of Missouri and trading is not allowed between eastern and western Missouri EGUs.

The Missouri rules spread the requirement for NOx reductions throughout the entire State. Thus, the emissions reductions are not focused in the geographical area of interest.

The NOx SIP Call budget also includes reductions in emissions from large cement kilns, industrial boilers, and stationary IC engines. The NOx SIP Call would allow fewer Draft   Do not cite, quote or distribute 134 emissions statewide, as shown in the table below. Table 2 below.

Table 2. Comparison of Ozone Reductions in the NOx SIP Call and the Missouri Statewide Rule EGU Emissions ( tons per ozone season) Fine Grid Statewide Actual 2001 Emissions 30,872 60,102 NOx SIP Call 13,400 cap 37,600a in 2001b, c MO current SIPapproved rule 23,100 in 2001c 46,900 in 2001c MO rule, potential revisionrevised rule 19,100 in 2001dc 49,600 in 2001c a. Assuming MOMissouri's current SIP approved rule remains effective in the coarse grid ( reductions from rule are included in the attainment demonstrations for St. Louis and Chicago).

b. The table only compares EGU emissions; the NOx SIP Call requires 2,900 tons additional NOx reductions due to controls on cement, industrial boilers and engines in the fine grid.

c. Estimated emissions based on actual 2001 heat input; emissions after 2001 would be higher as the State rule has no cap.

Further, we recently informed the State of some problem areas in their recent rule revisions. At least one of the proposed revisions appears to relax existing requirements;

that is, the delay of the compliance date from 2003 to 2004.

If this provision is adopted and submitted as a SIP Draft   Do not cite, quote or distribute 135 revision, the State must provide an adequate demonstration pursuant to section 110( l) of the CAA that this revision " would not interfere with any applicable requirement concerning attainment and reasonable further progress...."

As a practical matter, utilities have been on notice since original rule adoption that compliance would be expected in ozone season 2003, so an extension of the compliance date does not appear justified. A second area of serious concern in the proposed rule is the generation and use of " paper"

credits by allowing utilities to demonstrate compliance at the 0.18 lb/ mmBtu emission level but then receive credit at a 0.25 lbmm/ Btu emission level. This provision is inconsistent with our policy that credit for emission reductions must be real, quantifiable, surplus, enforceable,

and permanent. In addition to the issues above, there are other SIP approvability concerns with the Missouri statewide rule which make it likely that the rule would have to undergo further revision. These include concerns about the credibility of early reduction credits which appear not to be actual surplus.

D. What Are We Finalizing for Alabama and Michigan in Light of the Court Decision on Georgia and Missouri?

We calculated Alabama's and Michigan's budgets in the same manner as we did for Georgia and Missouri, as described Draft   Do not cite, quote or distribute 40 Both Georgia and Missouri submitted Phase I SIPs which included only the fine grid portion of the States.

136 above. While no petitioners raised any issues concerning the inclusion of only parts of Alabama and Michigan in the NOx SIP Call, the Court's reasoning regarding Georgia and Missouri applies equally to Alabama and Michigan. Based on the information in the record, we revised the NOx budgets for Alabama and Michigan to reflect reductions only in the fine grid portions of these States. 40 Again, like Georgia and Missouri, we see no reason to disturb the determination that sources in the fine grid contribute significantly to nonattainment downwind; the fine grid portions of both Alabama and Michigan are closer to downwind 1 hour ozone nonattainment areas than the coarse grid parts of these States. Also, the amount of NOx emissions per square mile in the fine grid portion of Alabama is nearly 60 percent greater than in the coarse grid part; and in Michigan the fine grid NOx emissions per square mile are more than 500 percent greater than emissions per square mile in the coarse grid portion of the State. Counties in Michigan and Alabama which straddle the fine grid coarse grid are excluded from the budget calculations as described above for Georgia and Missouri. We believe this approach is consistent with the reasoning of the Court's March 3, 2000 opinionholding in Draft   Do not cite, quote or distribute 41 Pursuant to the court's order lifting the stay of the SIP submission obligation, the 1920 States, including Alabama, Michigan, and the District of Columbia, were required to submit SIPs in response to the NOx SIP Call by October 30, 2000. As discussed above, in letters dated April 11, 2000 to State Governors, we informed the States that remained subject to the NOx SIP Call that they could choose to submit SIPs meeting only the Phase I emissions budget for each State. With respect to Alabama and Michigan, we also provided that they could choose to submit SIPs that address emissions only in the fine grid portion of the State. Alabama and Michigan submitted Phase I SIPs which included only the fine grid portion of the States.

137 Michigan concerning Georgia and Missouri and is justified as provided above. 41 The counties in Alabama and Michigan that are included in the calculation of NOx budgets for each of these States are listed in Table 23.

Table 23. Fine Grid Counties in Alabama and Michigan Alabama Autauga Co Colbert Co Greene Co Macon Co St. Clair Co Bibb Co Coosa Co Hale Co Madison Co Shelby Co Blount Co Cullman Co Jackson Co Marion Co Sumter Co Calhoun Co Dallas Co Jefferson Co Marshall Co Talladega Co Chambers Co De Kalb Co Lamar Co Morgan Co Tallapoosa Co Cherokee Co Elmore Co Lauderdale Co Perry Co Tuscaloosa Co Chilton Co Etowah Co Lawrence Co Pickens Co Walker Co Clay Co Fayette Co Lee Co Randolph Co Winston Co Cleburne Co Franklin Co Limestone Co Russell Co Michigan Allegan Co Eaton Co Kalamazoo Co Monroe Co St. Clair Co Barry Co Genesee Co Kent Co Montcalm Co St. Joseph Co Bay Co Gratiot Co Lapeer Co Muskegon Co Sanilac Co Berrien Co Hillsdale Co Lenawee Co Newaygo Co Shiawassee Co Branch Co Ingham Co Livingston Co Oakland Co Tuscola Co Calhoun Co Ionia Co Macomb Co Oceana Co Van Buren Co Cass Co Isabella Co Mecosta Co Ottawa Co Washtenaw Co Clinton Co Jackson Co Midland Co Saginaw Co Wayne Co E. What Modifications Are Being Made to the NOx Emissions Budgets? Draft   Do not cite, quote or distribute 138 In today's final action, in a change from the proposed rule, we are excluding certain small cogeneration units from the definition of EGU. All other cogeneration units and other non acid rain units will remain as EGUs. As a result,

it makes sense to require States to include in their Phase II SIPs the anticipated emissions reductions from non Acid Rain units. However, since, as discussed below, States seem to have already included non Acid rRain units in the Phase I SIPs, today's action concerning the EGU definition will have little or no effect on State budgets and required reductions.

We are also finalizing technical changes to the EGU definition in the NOx SIP Call to make it consistent with the definition of EGU used in the Section 126 Rule. Since the EGU definition establishes the dividing line between the EGU and non EGU categories, the changes to the EGU definition result in corresponding changes to the non EGU definition in the NOx SIP Call, which make it consistent with the non EGU definition in the Section 126 Rule.

Today's action concerning these definitions does not result in any specific revisions to the budgets established under the final NOx SIP Call and the Technical Amendments.

We are recalculating the budgets to reflect a control level of 82 percent for the natural gas fired lean burn IC Draft   Do not cite, quote or distribute 139 engines. For the other IC engine subcategories ( diesel and dual fuel) we are using 90 percent control, as proposed.

We are calculating the budgets for Georgia, Missouri,

Alabama, and Michigan assuming controls in all counties that are fully located in the fine grid, as discussed in sections II. C. and II. D. The partial State budgets for Georgia,

Missouri, Alabama, and Michigan in today's action are calculated using IC engine control, as well as the definition of EGUs as described above.

Our budgets are shown in Tables 34 and 45. For States that are required to submit Phase I SIPs, Table 56 shows the Phase I and Phase IIfinal budgets and the incremental difference between the two budgets. We are requiring States that have submitted SIPs that meet only the Phase I budget to supplement their control plans with rules that will meet the Phase II increment.

Table 3The budget numbers in Tables 4 and 5 are based on the NOx SIP Call emission inventory as revised in the " Technical Amendment to the Finding of Significant Contribution and Rulemaking for Certain States for Purposes of Reducing Regional Transport of Ozone," which was published on March 2, 2000. The EPA first published minor changes to the NOx SIP Call emission inventory in a Technical Amendment published May 14, 1999, in response to Draft   Do not cite, quote or distribute 140 comments on the 2007 baseline sub inventory in the NOx SIP Call published October 27, 1998. After the first Technical Amendment was published, EPA received further comments stating that the baseline sub inventory contained errors.

In response to these comments, EPA published the second Technical Amendment on March 2, 2000, in which changes were made to the baseline inventory and budgets for the NOx SIP Call for submitted data which was determined to be technically justified.

In some cases, States have made minor corrections to their NOx SIP Call emission inventory as part of their response to the NOx SIP Call requirements. States making corrections include, for example, Kentucky, Illinois, and Indiana. The EPA has evaluated these corrected emission inventories on a case by case basis and, as appropriate,

approved the corrections as part of the rulemaking on the State's NOx SIP Call submittal. Today's rulemaking on the Phase II NOx SIP Call requirements is based on the corrections to the NOx SIP Call emission inventory published March 2, 2000 and does not take into account these corrections made in the individual State rulemaking actions.

Furthermore, additional corrections may be made in the future to certain State emission inventories due, for example, to the change in the definition of EGU. As stated Draft   Do not cite, quote or distribute 141 in the NOx SIP Call, "[ t] he control measures that the State chooses to require will become the enforceable mechanism under the NOx SIP Call" ( 63 FR 57426, October 27, 1998).

The reader should refer to both this final rule and individual rulemaking actions on each State's SIP revision in response to the NOx SIP Call for more information.

In cases where the Phase I budget in a State's approved SIP revision differs from the EPA budget, due to changes in sources approved by EPA, the State is required to achieve the incremental Phase II reductions shown in Table 6 in order to meet the full NOx SIP Call. In cases where the State has voluntarily submitted, and EPA has approved Phase I SIPs with budgets more stringent than required by EPA, the State is required to achieve the final budgets shown in Table 6.

Table 4. State Emissions Budgets and Percent Reduction ( tons/ season)

State Final Base Phase II Final Budget Tons Reduced Percent Reduction Connecticut 46,015 42,850 3,165 7% Delaware 23,797 22,862 935 4% District of Columbia 6,471 6,657  186  3%

Illinois 368,870 271,091 97,779 27% Draft   Do not cite, quote or distribute 142 Indiana 340,654 230,381 110,273 32% Kentucky 237,413 162,519 74,894 32% Maryland 103,476 81,947 21,529 21% Massachusetts 87,095 84,848 2,247 3% New Jersey 105,489 96,876 8,613 8% New York 255,658 240,322 15,336 6% North Carolina 224,696 165,306 59,390 26% Ohio 373,222 249,541 123,681 33% Pennsylvania 345,203 257,928 87,275 25% Rhode Island 9,463 9,378 85 1% South Carolina 152,805 123,496 29,309 19% Tennessee 256,765 198,286 58,479 23% Virginia 210,786 180,521 30,265 14% West Virginia 176,699 83,921 92,778 53%

Table 45. Partial State Emissions Budgets and Percent Reduction ( tons/ season)

State Final Base Final Budget Tons Reduced Percent Reduction Georgia 209,914 150,656 59,258 28% Missouri 92,697 61,406 31,291 34% Alabama 169,156 119,827 49,329 29% Michigan 245,929 190,908 55,021 22%

Table 56. Comparison of Phase I and Phase II State NOx Budgets Comparison ( tons/ season)

State Phase I Budget Phase IIFinal Budget Phase II Incremental Difference Alabama 124,795 119,827 4,968 Connecticut 42,891 42,850 41 Delaware 23,522 22,862 660 Draft   Do not cite, quote or distribute 143 District of Columbia 6,658 6,657 1 Illinois 278,146 271,091 7,055 Indiana 234,625 230,381 4,244 Kentucky 165,075 162,519 2,556 Maryland 82,727 81,947 780 Massachusetts 85,871 84,848 1,023 Michigan 191,941 190,908 1,033 New Jersey 95,882 96,876  994 New York 241,981 240,322 1,659 North Carolina 171,332 165,306 6,026 Ohio 252,282 249,541 2,741 Pennsylvania 268,158 257,928 10,230 Rhode Island 9,570 9,378 192 South Carolina 127,756 123,496 4,260 Tennessee 201,163 198,286 2,877 Virginia 186,689 180,521 6,168 West Virginia 85,045 83,921 1,124 F. How Will the Compliance Supplement Pools be Handled?

The compliance supplement pool ( CSP) is a pool of allowances that can be used in the beginning of the program to provide affected sources additional compliance flexibility. The CSP was created to address concerns raised by commenters on the NOx SIP Call proposal regarding electric reliability during the initial years of the program. In the NOx SIP Call Rule, the CSP may be used in the years 2003 and 2004 ( see 63 FR 57428 57430, October 27,

1998, for further discussion of the CSP). In Michigan, the D. C. Circuit Court ruled that May 31, 2004, rather than May 1, 2003 is the date by which sources must install controls Draft   Do not cite, quote or distribute 144 to comply with the NOx SIP Call. Consequently, to be consistent with the original 2 year window specified in the NOx SIP Call in which we allowed the CSP allowances to be used, we are finalizing an extension of the time that allowances from the CSP can be used from September 30, 2004 to September 30, 2005 for sources with a May 31, 2004 compliance date, and to September 30, 2008 for sources with a May 1, 2007 compliance date. We are also including CSPs for Georgia and Missouri. As under the original NOx SIP Call, Georgia and Missouri may distribute the allowances in their respective pools either based on early reductions,

directly to sources based on a demonstrated need, or by some combination of the two methods. ( For a more complete discussion of how CSP allowances may be distributed under the NOx SIP Call, see 63 FR 57429.) The allowances from Georgia's and Missouri's CSPs may be used to account for emissions during the 2007 and 2008 ozone seasons, the first 2 years' ozone seasons that sources in those States are required to comply.

We are not changing the individual State CSP values that were finalized in the March 2, 2000 technical corrections to the emission budgets ( 65 FR 11222) with the exception of Alabama, Georgia, Michigan, Missouri, and Wisconsin. Changing the State CSPs to reflect the State Draft   Do not cite, quote or distribute 145 budget changes made in this action would result in minimal impacts on the size of any State's CSP. Therefore, we have decided to maintain the CSPs at the levels determined in the March 2, 2000 technical amendment ( with the exception of Alabama, Georgia, Michigan, Missouri, and Wisconsin).

Since required reductions in Georgia, Missouri,

Alabama, and Michigan finalized under today's final rule are less than the required reductions of the October 27, 1998 NOx SIP Call reflecting full State emissions budgets, we are making corresponding decreases to the CSPs for the portion of each State that is still subject to the NOx SIP Call. We have calculated the partial State CSPs by prorating the size of the full State CSP by the ratio of the reductions that we are finalizing for the partial State to the reductions that we required in the March 2, 2000 Technical Amendment ( 65 FR 11222). However, even though we are finalizing an 82 percent reduction requirement from large natural gas fired IC engines, to be consistent with the way the CSP was calculated in the other States, we assumed a 90 percent reduction from all large IC engines for purposes of calculating the CSP. In addition, since Wisconsin is not being required to make reductions at this time, Wisconsin is no longer receiving a share of the CSP. ( Wisconsin's original CSP was 6,920 tons.) For these reasons, the total Draft   Do not cite, quote or distribute 146 CSP is now less than 200,000 tons. The revised CSPs for Georgia, Missouri, Alabama, and Michigan are shown in Table 67.

Table 67. Compliance Supplement Pools ( CSP)

Full State Tons Reduced ( from March 2, 2000 FR) Partial State Tons Reduced With 90% 90 percent IC Engine Control Full State CSP Partial State CSP With 90% 90 percent IC Engine Control GA 63,582 57,623 11,440 10,728 MO 62,242 31,291 11,199 5,630 AL 64,954 49,806 11,687 8,962 MI 63,118 55,064 11,356 9,907 One commenter ( EL Paso Corporation, OAR 2001 0008,

XIID 10), commented that IC engines should be allowed to receive reductions from the CSP. The commenter asserts that we have failed to recognize that the CSP contains NOx allocations generated by IC engines. The commenter also claims that because IC engines will also have to be retrofitted to comply with the NOx SIP Call they could also have reliability problems and, therefore, should be able to receive allowances from the CSP.

Under the NOx SIP Call, the CSP is limited to use by the large boilers and turbines that are in the NOx Budget Trading Program. Because IC engines are not in the NOx Budget Trading Program, they are not eligible to receive Draft   Do not cite, quote or distribute 147 allowances from the CSP. States have two options for making the pool available to sources in the trading program. One option is to distribute some or all of the pool to sources that generate early reductions during ozone seasons prior to May 1, 2003. The second option is to run a public process to provide tons to sources that demonstrate a need for a compliance extension. The pool was created to help that group of sources meet compliance deadlines without jeopardizing electric reliability. It was not created to address reliability problems in other sectors.

G. Will the EGU Budget Changes Affect the States Included in the Three State Memorandum of Understanding?

In February 1999, Connecticut, Massachusetts, Rhode Island, and EPA signed a Memorandum of Understanding ( the three State MOU). The three State MOU redistributed Connecticut, Massachusetts, and Rhode Island's EGU emissions budgets to minimize the size differential between their EGU budgets under the NOx SIP Call and Phase III of the OTC NOx Budget program. It also reallocated the three States' CSPs.

Under the three State MOU, Connecticut, Massachusetts,

and Rhode Island would collectively be meeting their NOx SIP Call reduction responsibilities because the budget redistribution did not result in a higher combined overall EGU budget for the three States. We took action to Draft   Do not cite, quote or distribute 148 implement the three State MOU and concurrently published proposed and direct final rules on September 15, 1999 ( 64 FR 50036 and 49987). We subsequently withdrew the direct final rule on November 1, 1999 due to the receipt of adverse comment ( 64 FR 58792). The EGU budgets in today's action will not affect the EGU budgets for Connecticut,

Massachusetts, and Rhode Island that we proposed in response to the three State MOU. We did not finalize the proposal to act on the three State MOU. Instead, we proposed to approve the three States' NOx SIP Call SIP submittals, with budgets that reflected the three State MOU, as collectively meeting their NOx SIP Call budgets. We did not receive any comments on the proposed approval of these three State's SIPs and finalized approval of them on December 27, 2000.

H. How Does the Term " Budget" Relate to Conformity Budgets?

We wish to clarify that the use of the term " budget" in this action does not refer to the transportation conformity rule's use of the term " motor vehicle emissions budget,"

defined at 40 CFR 93.101. The budgets finalized today do not set budgets for specific ozone nonattainment areas for the purposes of transportation conformity. Transportation conformity budgets cannot be tied directly to the NOx SIP Call budgets because the latter are for all or a large part Draft   Do not cite, quote or distribute 149 of the State and the former are nonattainment area specific.

For nonattainment or maintenance areas in a State covered by the NOx SIP Call, transportation conformity budgets must reflect the mobile source controls assumed in the NOx SIP Call budgets to the extent that the attainment SIP ultimately relies upon those controls.

I. How Will Partial State Trading be Administered?

In the final NOx SIP Call, we offered to administer a multi State NOx Budget Trading Program for States affected by the NOx SIP Call. In today's action, we are including only partial State budgets for Alabama, Georgia, Michigan,

and Missouri. Therefore, we will administer a trading program for the NOx SIP Call region that, for these four States, includes only the portion of the States we are including in the NOx SIP Call. In the final NOx SIP Call,

as well as the January 18, 2000 final rulemaking on the original eight Section 126 petitions, we authorized sources in States affected by either the NOx SIP Call or the Section 126 rulemaking to trade with each other through the mechanisms of the NOx Budget Trading Program provided certain criteria were met. These criteria included that States must be subject to the NOx SIP Call and that States must meet the emission control level under the final rule for the NOx SIP Call. The justification for allowing Draft   Do not cite, quote or distribute 42 Banked allowances are those allowances that are not used in the ozone season for which they are allocated and that are therefore carried into the next ozone season. Allowances from the CSP are considered banked at the start of the second year of the program. See 40 CFR 51.121( b)( 2)( ii)( D).

150 trading across States is the test of significant contribution which underlies both the Section 126 rulemaking and the NOx SIP Call. Therefore, at this time, only sources in the portions of the States for which a finding of significant contribution has been made and budgets have been established are allowed to participate in trading with sources in States which are subject to either the NOx SIP Call or the Section 126 rulemaking.

1. How Will Flow Control Be Handled for Georgia and Missouri?

The NOx SIP Call ( 63 FR 57356) includes a limitation ( referred to as " flow control") on the use of banked allowances for compliance with the requirement to hold allowances covering emissions from affected units. 42 In the NOx SIP Call, we noted that banking of allowances may inhibit or prohibit achievement of the desired emissions budget in a given [ ozone] season since the use of banked allowances for compliance for a specific ozone season may result in total emissions for affected units exceeding the trading budget for that ozone season ( 63 FR 25902, 25935; Draft   Do not cite, quote or distribute 151 May 11, 1998). The trading budget reflects the emissions reductions mandated, and found to be highly cost effective,

under the NOx SIP Call in order to prevent significant contribution to nonattainment in downwind States. Flow control addresses the potential problem caused by banking by continuing to allow unlimited banking of unused allowances but discouraging the " excessive use" of banked allowances for compliance. Id.; see also 63 FR 57473.

Flow control discourages the excessive use of banked allowances by discounting the use of banked allowances for compliance over a specified threshold. This threshold was set at 10 percent in the NOx SIP Call and applies to the entire NOx SIP Call region. The number of banked allowances held in all allowance tracking system ( ATS) accounts under the trading program is tabulated when each ozone season is completed to determine what percentage banked allowances comprise of the total multi State trading budget for the next ozone season. If this percentage is greater than 10 percent, flow control is triggered, and a withdrawal ratio is established for that next ozone season. The withdrawal ratio is calculated by dividing 10 percent of the total multi state trading program budget for that next ozone season by the total number of banked allowances at the end of the completed ozone season. The ratio is then applied to Draft   Do not cite, quote or distribute 152 each ATS compliance account that holds banked allowances at the end of that next ozone season. A unit can use banked allowances for compliance without restriction ( i. e., on a one allowance to one ton basis) in an amount not exceeding the amount in the unit's compliance account times the withdrawal ratio. Banked allowances used for compliance in an amount exceeding that determined using the withdrawal ratio must be used on a two allowances for one ton basis.

The NOx SIP Call provided that flow control provisions apply starting in the second year of the NOx SIP Call program. ( The first ozone season in which flow control applies and can be triggered is referred to as the " flow control date.") Specifically, the NOx SIP Call established May 1, 2003 as the commencement date for the NOx SIP Call program and required the flow control provisions to apply starting in the second year ( i. e., 2004). See 40 CFR 51.121( b)( 1)( ii) and ( b)( 2)( ii)( E). Subsequent to the initial NOx SIP Call rulemaking, the D. C. Circuit delayed the commencement date for the NOx SIP Call program to May 31, 2004, and so the second year of the program  and the required flow control date  for State programs beginning in 2004 became 2005. While the regulations ( § 51.121 and part 96) were not revised, we have implemented the new flow control date through the notice and comment rulemakings for Draft   Do not cite, quote or distribute 43 In approving trading program rules for Connecticut, Delaware, District of Columbia, Maryland, Massachusetts, New Jersey, New York, and Rhode Island, we approved flow control dates of 2004 based on the initial NOx SIP Call Rule, under which the program started May 1, 2003. ( We note that we erroneously approved 2005 as the flow control date for Pennsylvania, whose program also begins in 2003.) After the Court established May 31, 2004 as the commencement date for the NOx SIP Call program, we approved 2005 as the flow control date for States ( i. e., Alabama, Illinois, Indiana, Kentucky, North Carolina, South Carolina, Tennessee, and West Virginia) whose programs begin in 2004. We also approved NOx SIP Call rules for two States ( Ohio and Virginia) on the condition that a 2005 flow control date be adopted.

44 Although we approved several State programs with a 2004 flow control date ( see n. footnote number 43), 2005 is the earliest year that flow control is likely to be triggered for those States. For 2004, the calculation for triggering flow control is the total number of banked allowances in accounts as of December 1, 2003 ( i. e., only the unused allowances allocated for 2003 plus the CSP allowances for those States with programs beginning in 2003) divided by the total trading budgets for the States with programs in effect in 2004 ( i. e., virtually all States in the NOx SIP Call region). Because, for this calculation for 2004, the number of States reflected in the numerator is so much smaller than the number of States reflected in the denominator, 2005 is effectively the flow control date for all States whose programs begin in 2003.

153 approval of the SIPs. We have approved rules under the NOx SIP Call for 17 sStates and the District of Columbia. The approved rules provide for a flow control date of 2004 or 2005,43 and, as a practical matter the earliest date that flow control can be triggered in any of these States and the District of Columbia is 2005.44 It is our general intent to treat affected units in Georgia and Missouri in essentially the same manner as Draft   Do not cite, quote or distribute 154 affected units under Phase I of the NOx SIP Call. Once Georgia and Missouri submit SIPs in accordance with today's rule, we will review these SIPs in light of our general intent. As we did in the case of the SIPs submitted by States under Phase I of the NOx SIP Call, we will address,

in the context of reviewing Georgia's and Missouri's SIPs,

such issues as the flow control provisions and the flow control date and are not revising the flow control date in § 51.121 and part 96.

However, we note that if the flow control provisions in the initial NOx SIP Call Rule were applied to Georgia and Missouri, potential problems could arise because the units in those States would have a flow control date, i. e., the second year ( 2008) of those States' programs, that is 3 years later than the effective 2005 flow control date for units in States in Phase I of the NOx SIP Call. We will consider and resolve these potential problems when we review Georgia's and Missouri's SIPs rather than in today's rule.

In order to provide guidance to Georgia and Missouri in the development of their SIPs, we are discussing below these potential problems.

The potential problems in applying the flow control provision in § 51.121 and part 96 to Georgia and Missouri are as follows. Allowing 2008 to be the flow control date in Draft   Do not cite, quote or distribute 155 Georgia ( or Missouri) could result in an unfair advantage for units in that State over units in other States with an effective 2005 flow control date. Specifically, for the 2007 ozone season when the Georgia ( or Missouri) programs begin, banked allowances held for Georgia ( or Missouri)

units or by Georgia ( or Missouri) companies as of November 30, 2006 could be a contributing factor for triggering flow control in 2007 for all other States with programs that are in effect. If Georgia ( or Missouri) units were to help trigger flow control in 2007 but would not be subject to the flow control limitation on use of banked allowances in 2007,

this would give Georgia ( or Missouri) units an unfair advantage over units in the other States.

Further, should a 2008 flow control date be approved for Georgia ( or Missouri), this would allow some companies to circumvent the earlier flow control dates established by other States. A company with affected units in both Georgia ( or Missouri) and a State with an effective 2005 flow control date would be particularly advantaged in this regard. Such a company could circumvent the earlier flow control date by exchanging banked allowances held for its units in the State with the 2005 flow control date for 2007 allowances held for its units in Georgia ( or Missouri). All of these banked allowances could be used in Georgia ( or Draft   Do not cite, quote or distribute 156 Missouri) in 2007 without application of flow control.

Moreover, a company with only units in States with earlier flow control dates could also circumvent, to some extent,

the flow control provisions of those States. To the extent that the latter company could purchase 2007 allowances and sell banked allowances, it could also avoid the application of the flow control limitation in 2007. In short, allowing a 2008 flow control date for Georgia ( or Missouri) would allow erosion of the effectiveness of flow control for States with an effective 2005 flow control date and would give an unfair advantage to some companies.

We believe these potential problems might be avoided if, under Georgia's and Missouri's SIPs, flow control is effective starting in the first year ( 2007) of their programs while CSP allowances for those States continue to be treated as banked allowances starting in the second year ( 2008) of their programs. This approach would appear to prevent companies from being able to circumvent the effective 2005 flow control dates in other States' programs since banked allowances  whether held by units or companies in Georgia or Missouri or in other States  would be subject to flow control in 2007. Transferring banked allowances to Georgia or Missouri units or companies would not avoid flow control if it is triggered. Draft   Do not cite, quote or distribute 157 It also appears that applying flow control in the first year of the program in Georgia and Missouri would not disadvantage units and companies in Georgia and Missouri with regard to their CSP allowances. The NOx SIP Call established that the CSP could be used in the first 2 years of a State's trading program without the application of flow control to the CSP allowances in the first year. Under the approach discussed above, the allowances from Georgia's and Missouri's CSPs ( like the CSPs for other States) would be available for use in the first and second years ( 2007 and 2008 for Georgia and Missouri). Because the CSP allowances would not be considered banked until 2008, these allowances could be used in the first year of the program ( 2007)

without being affected by flow control. Thus, the Georgia and Missouri CSP allowances could be used in 2007 without limit regardless of whether flow control is triggered at the end of the 2006 ozone season and could not trigger flow control at the end of 2007.

As noted above, today's rule does not establish a flow control date for Georgia and Missouri. Instead, we are indicating how we intend to address this issue when we review the Georgia and Missouri SIPs, and we will consider,

in conducting those reviews, the approach discussed above and any other approach that is proposed for addressing the Draft   Do not cite, quote or distribute 158 issue.

J. What Is the Phase II SIP Submittal Date?

In today's action, we are setting a date for States to submit SIPs meeting the Phase II NOx budgets and the partial State budgets for Georgia and Missouri. We believe that an adequate timeframe for SIP submittal is 12 months from signature date of this rulemaking. We believe that this schedule will allow adequate time for States to promulgate rules, and for sources affected by a State's Phase II NOx strategy and by Georgia and Missouri's NOx strategy to comply with the regulations by the dates in this action.

Please see section K, below, for a discussion of the compliance dates.

Comment: Several commenters contend that the range of proposed SIP submittal dates ( i. e., 6 months to a year from final promulgation of this rulemaking, but no later than April 1, 2003) does not allow enough time for States to develop a SIP. They noted that this is due to the fact that the proposal was published on February 22, 2002 and the comment period was scheduled to end on April 15, 2002, and that the final rule would not be promulgated in time to allow adequate time for States to complete their rulemaking processes. These commenters fell into several categories based on their recommendation for a SIP submittal date: ( 1) Draft   Do not cite, quote or distribute 159 EPA is not allowing enough time for SIP submittal; ( 2) EPA should set a SIP submittal date 12 months from the date of final promulgation of this rule; ( 3) EPA should allow more than 12 months for States to submit SIPs; and ( 4) EPA should allow 18 months for SIP submittal as authorized in section 110( k)( 5).

Response: After considering these comments, we are requiring that SIP revisions be submitted within 12 months after the date of signature of this final rule. We believe this is adequate time for States to submit SIP revisions reflecting the reductions required by this phase of the NOx SIP Call. In response to the court decision in Michigan v.

EPA, 213 F. 3d 663 ( D. C. Cir. 2000), cert. denied, 121 S. Ct.

1225 ( 2001), we divided the NOx SIP Call into two phases   Phase I which accounted for 90 percent of the total reductions required by the NOx SIP Call, and Phase II which will achieve approximately 10 percent of the total reductions required by the NOx SIP cCall. Thus, because Phase II of the NOx SIP Call requires relatively smaller NOx emissions reductions and because it applies to a much smaller subset of sources, we believe that 12 months is adequate time for States to develop and submit the required SIP revisions. In addition, as earlier stated, this action is being taken under section 110( k)( 5) which requires SIP Draft   Do not cite, quote or distribute 160 revisions within a specified period but " not to exceed 18 months" after a finding of inadequacy by the Agency.

Initially we had allowed States 12 months for submittal of SIPs meeting the full NOx SIP Call, with September 30,

1999 as the submission date. On May 25, 1999, in response to a request by States challenging the NOx SIP Call, the D. C. Circuit issued a stay of the SIP submission deadline pending further order of the Court. Michigan, 213 F. 3d 663 ( D. C. Cir. 2000), cert. denied, 121 S. Ct. 1225 ( 2001) ( May 25, 1999 order granting stay in part). Subsequently, we filed a motion on April 11, 2000, requesting the court to lift the stay of the SIP submission date and on June 22,

2000, the court lifted the stay and established October 30,

2000, as the new SIP submission date. Thus, by setting this submission date, the Court recognized the 12 month submission schedule required in the NOx SIP Call.

In setting this time frametimeframe, we also recognize that the proposed NOx SIP submittal date of 6 months to 1 year from final promulgation of this rulemaking, but no later than April 1, 2003, is no longer appropriate due to the February 22, 2002 publication date of the proposed rule.

We are also aware that some States have lengthy rulemaking processes that may require longer than 12 months for full adoption of regulations. However, States have the ability Draft   Do not cite, quote or distribute 161 to set their rulemaking procedures and can provide adequate mechanisms to adopt regulations to address interstate transport. Many States already have emergency or other shortened procedures in place in order to bypass regular rulemaking procedures in certain circumstances. We also note that some States have already adopted SIPs that comply fully with the NOx SIP Call.

Moreover, we note that States that fail to submit SIPs within 12 months are not precluded from submitting plans after that date. Areas will not be subject to mandatory sanctions under section 179 of the CAA until 18 months after we find that the State failed to submit a plan in response to the NOx SIP Call. Furthermore, if the State makes a late submission, our approval of that program would serve to replace any Federal plan that may have taken effect in the interim. We note that States can submit draft plans ( i. e.,

plans that have not completed the final steps in the State administrative process) for parallel processing. See 47 FR 2703 ( June 23, 1982). While this type of submission may not preclude a finding of failure to submit, it can help ensure that the State program is approved as a SIP revision and as a replacement for any promulgated Federal implementation plan) in the most expeditious manner. Also, as we did for the Phase I NOx SIP submittals, the EPA Regional Offices and Draft   Do not cite, quote or distribute 45 Technical Support Document, " Responses to Significant Comments on the Proposed Finding of Significant Contribution and Rulemaking for CertainStatesCertain States in the OTAG Region for Purposes of Reducing Regional Transport of Ozone," Docket No. A 96 56, Item No. VI C 01, September 1998.

162 Headquarters will work closely with the States to ensure that approvability issues are quickly resolved in order to allow SIPs to be submitted as expeditiously as possible. 45 [( Section II. J, OAR 2001 0008, comments XII D 28, XII D 29).

K. What Are the Phase II Compliance Dates?

We are setting a Phase II compliance date of May 1,

2007. This date is 24 months after the SIP submittal date plus the days until the next ozone season begins. However,

sources already controlled in an approved Phase I SIP are required to meet the compliance date stipulated in that SIP,

including non Acid Rain EGUs and any cogeneration units that were previously classified as EGUs and whose classification changed to non EGUs under today's rule.

In this section, it is important to note that although compliance dates are discussed for certain EGUs and, non

EGUs, and IC engines, States may choose to control other sources. As stated in the original NOx SIP Call:

" States are not constrained to adopt measures that mirror the measures EPA used in calculating the budgets. In fact, EPA believes that many control measures not on the list relied upon to develop Draft   Do not cite, quote or distribute 163 EPA's proposed budgets are reasonable   especially those, like enhanced vehicle inspection and maintenance programs, that yield both NOx and VOC emissions reductions. Thus, one State may choose to primarily achieve emissions reductions from stationary sources while another State may focus emission reductions from the mobile source sector." ( 63 FR 57378, October 27, 1998).

1. How Are We Handling Non Acid Rain EGUs and Any Cogeneration Units That Were Previously Classified as EGUs and Whose Classification Changed to Non EGUs Under Today's Rule?

We proposed a compliance date of May 31, 2004 ( or, if later, the date on which the source commences operation) for all Phase II EGUs and non EGUs in Alabama, Connecticut,

District of Columbia, Delaware, Illinois, Indiana, Kentucky,

Massachusetts, Maryland, Michigan, North Carolina, New Jersey, New York, Ohio, Pennsylvania, Rhode Island, South Carolina, Tennessee, Virginia, and West Virginia. We also proposed a compliance date of May 1, 2005 ( or, if later, the date on which the source commences operation) for all sources in Georgia and Missouri. The compliance dates mark the beginning of the periods during which units in the trading program must hold at least enough NOx allowances to cover their ozone season NOx emissions.

The proposed compliance date of May 31, 2004 ( or, if later, the date on which the source commences operation) was Draft   Do not cite, quote or distribute 46 We note that the non EGU classification of those cogeneration units that have been consistently treated as non EGUs in the NOx SIP Call and the Section 126 Rule was not remanded and vacated by the Court, and we maintain that the May 31, 2004 compliance date for such units is not at issue in today's rulemaking. However, even assuming arguendo that their compliance date were at issue, there would be no basis for establishing a later compliance date since these units ( like, e. g., the non Acid Rain EGUs) are already subject to the May 31, 2004 date under the Phase I SIPs.

164 designed to provide Phase II EGUs and non EGUs a little over 12 months after the deadline for State submission of Phase II SIPs covering such units to install any necessary emission controls. In today's rule, we are finalizing a deadline of [ insert date 12 months after signature] for submission of Phase II SIPs. However, we believe that for all of the States ( except Georgia and Missouri, which are addressed separately below), non Acid Rain EGUs and any cogeneration units that were previously classified as EGUs and whose classification changed to non EGUs under today's rule were included in the Phase I SIPs that were already submitted. 46 Several States ( i. e., Connecticut, District of Columbia, Delaware, Massachusetts, Maryland, New Jersey, New York, Pennsylvania, and Rhode Island) have submitted SIPs that cover non Acid Rain EGUs and any cogeneration units whose classification changed from EGUs to non EGUs under today's rule, as well as Phase I EGUs and non EGUs, and require compliance with the allowance holding requirement Draft   Do not cite, quote or distribute 165 starting May 1, 2003 ( or, if later, the date on which the source commences operation). The remaining States other than Georgia and Missouri ( i. e., Alabama, Illinois, Indiana,

Kentucky, Michigan, North Carolina, Ohio, South Carolina,

Tennessee, Virginia, and West Virginia) have submitted SIPs that cover non Acid Rain EGUs and any cogeneration units whose classification changed from EGUs to non EGUs under today's rule, as well as Phase I EGUs and non EGUs and require compliance starting May 31, 2004 ( or, if later, the date on which the source commences operation). The coverage of non Acid Rain EGUs and any cogeneration units whose classification changed from EGUs to non EGUs under today's rule is reflected both in the applicability provisions in the various SIPs   which provisions cover EGUs and non EGUs without assuming any non Acid Rain units or any cogeneration units   and in the State budget demonstrations and allowance allocations   which list the affected units including the non Acid Rain EGUs and any cogeneration units whose classification changed from EGUs to non EGUs under today's rule. ( See docket Item No.___). Although, elsewhere in today's final rule, we are revising the definition of EGU and non EGU, we believe that these revisions will require the reclassification of few, if any, units as EGUs and non

EGUs and will not make any additional units subject to the Draft   Do not cite, quote or distribute 47 To the extent that the revisions of the EGU and non EGU definitions have such an impact on any specific units, we will address the matter in connection with our review of the relevant State Phase II SIP provisions.

166 NOx SIP Call. See section II. A. 4 of this preamble. 47 Since all Phase II non Acid Rain EGUs and any cogeneration units whose classification changed from EGUs to non EGUs under today's rule in these States are already subject to a compliance date of May 1, 2003 or May 31, 2004 ( or, if later, the date on which the source commences operation), we see no basis for extending the NOx SIP Call compliance deadline beyond the date stipulated in the Phase I SIPs under which these units are covered. The CAA rests on an " overarching" principle that the NAAQS be achieved as expeditiously as possible ( 63 FR 57356, 57449, October 27,

1998). For example, under section 181 of the CAA, the " primary standard attainment date for ozone shall be as expeditiously as practicable but not later than [ certain statutorily prescribed attainment dates]." 42 U. S. C. 7511;

see also 42 U. S. C. 7502( a)( 2)( A). The State trading budgets under the NOx SIP Call reflect the emissions reductions mandated under the NOx SIP Call in order to prevent significant contribution to nonattainment in downwind States. Under these circumstances, we believe that the CAA's overarching objective of expeditious as practicable attainment applies to these units. Draft   Do not cite, quote or distribute 167 A number of commenters ( including several States that have adopted SIPs with May 31, 2004 compliance dates for non Acid Rain EGUs and any cogeneration units whose classification changed from EGUs to non EGUs under today's rule) suggested that a compliance date of May 31, 2004 did not provide sources enough time to install emission controls. Some commenters suggested that units should be given 2 years after submittal of SIPs to comply. Several other commenters suggested that a compliance deadline should be set 1,309 days after the required SIP submittal date to be consistent with the D. C. Circuit's August 30, 2000 order related to compliance dates under the NOx SIP Call. As explained above, we do not believe it is necessary or appropriate to extend the compliance date beyond May 31,

2004 because the States involved have already adopted rules requiring non Acid Rain EGUs and any cogeneration units whose classification changed from EGUs to non EGUs under today's rule to comply by that date or earlier. It should also be noted that, even if the units had not already been included in the State's Phase I SIPs, the 1,309 day period used for setting the May 31, 2004 compliance date for Phase I SIPs would not be appropriate for those units. The Court's decision to provide units 1,309 days after submittal of SIPs was based on the amount of time that we provided Draft   Do not cite, quote or distribute 168 units to comply with the original NOx SIP Call, which had a compliance deadline of May 1, 2003. The original NOx SIP Call required States to make significantly more emissions reductions ( i. e., all the reductions that were subsequently designated as either Phase I or Phase II reductions in response to the Court's decision) than the reductions ( i. e.,

only the Phase II reductions for non Acid Rain EGUs and any cogeneration units whose classification changed from EGUs to non EGUs under today's rule) addressed here. Greater emissions reductions require the installation of more emission controls, which in turn requires more resources such as boiler makers and cranes. The analysis that we performed for the proposed Phase II rule shows that less time is required to install emission controls for the smaller number of Phase II units than the significantly larger number of Phase I units in the trading program.

2. What Compliance Date Are We Finalizing for IC Engines and What is the Technical Feasibility of tThis Date?

We are setting a compliance date for IC engines of May 1, 2007 ( or, if later, the date on which the source commences operation). This date is 24 months after the SIP submittal date plus the days until the next ozone season begins.

Comment: Several commenters from the pipeline industry Draft   Do not cite, quote or distribute 169 suggest the need to stagger or phase in the compliance activities over several years. Additional comments from the pipeline industry state that we ignore time needed to get permits; that we assume 160 engines would be off line in the same winter heating season; and that we failed to consider the problem of having multiple engines at one facility subject to retrofit requirements during the same short compliance timeframe.

Comments from 22 citizen groups recommend the May 2004 and May 2005 dates ( or, if later, the date on which the source commences operation), as proposed. One State supports the May 2005 compliance deadline proposed. All other commenters request that we provide more time than was proposed. Another State believes that a minimum of 24 months from the date of final SIP submittals is needed for sources to complete the necessary construction and installation of controls to comply with the Phase II provisions. A third State recommends the compliance date be 1,309 days after the SIP submittal date. Pipeline industry comments generally recommend May 2007 or 36 to 43 months from SIP submittal. These commenters refer to the 1998 NOx SIP Call Rule which gave 43 months from SIP submittal.

Utility group comments also recommend we should apply the same 1,309 day compliance period for the Phase II NOx SIP Draft   Do not cite, quote or distribute 48 See Docket No. OAR 2001 00098, Item # No. XII E 01.

170 Call requirements that applies to sources for the Phase I compliance pursuant to the original NOx SIP Call Rule schedule.

Response: The pipeline industry has considerable experience with the installation of LEC technology. While there is some evidence that installation of controls on a few engines within 1 year is reasonable, installing controls on many engines in a narrow timeframe is more problematic. As discussed below, we believe that the proposed timeframe of about 13 months should be extended to a minimum of 24 months from the SIP submittal date and the initial compliance date should occur within the ozone season.

We obtained additional information regarding this issue. One manufacturer estimated the time between request for cost proposal and contract to be 2 to 5 months and typically 3 to 4 months. It then takes 4 to 5 months for delivery and an additional 1 month to install and commence operation. This adds up to a total of 7 to 11 months. 48 Another manufacturer estimated the time between cost proposal and contract is 2 to 4 weeks to obtain bids; 2 to 3 months for selection of bids; 12 to 20 weeks for parts delivery to site; and 2 weeks to 1 ½ months for field Draft   Do not cite, quote or distribute 49 See Docket No. OAR 2001 0008, Item No. XII E 02.

50 See http:// www. dieselsupply. com/ dscartic. htm for reprint of article from May 1998 of " American Oil & Gas Reporter."

171 installation. 49 Another manufacturer estimated from request for cost bids to shipping of parts takes 6 to 8 months for delivery and an additional 2 to 4 weeks to install and commence operation. This adds up to a total of 6 to 9 months. 1749 Information from the Ventura County Air Pollution Control District in California estimated 2 weeks to 1 month to install LEC and the total time estimated from request for cost proposal and commencing operation of LEC was 6 to 9 months. A gas pipeline company, CMS Energy,

stated that a compliance schedule of 11 months was easy to meet for one to two engines but would put a stress on the system for 200 engines. Columbia Gas Transmission Corporation installed controls on two engines in Bedford County, Pennsylvania in 3 days, meeting the 3.0 g/ bhp hr standard set by the State. 50 Thus, there is some agreement that the necessary compliance period for installation of controls on a small number of engines is less than 1 year.

We disagree with the comment that 160 engines would be off line at the same time. We expect some companies to choose to phase in installation of the control equipment over a 2 year period ( or longer if the companies begin retrofit activities sooner) and that installation activities Draft   Do not cite, quote or distribute 51 Memo from Lydia Wegman, Director, Air Quality Strategies and Standards Division, U. S. EPA to Air Division Directors, U. S. EPA Regions I V, VII ( August 22, 2002), providing guidance on issues related to stationary IC engines and the NOx SIP Call.

172 would occur primarily in the summer along with normally scheduled maintenance activities. Further, as noted below,

not all of the potentially affected IC engines should be expected to need LEC retrofits and not in the same timeframe.

In response to Phase II of the NOx SIP Call, some States may seek emissions reductions from source categories other than IC engines. Other States have already met their NOx budgets and do not need to further control IC engines for purposes of the NOx SIP Call. Still other States have met at least a portion of the Phase II NOx SIP Call reductions due to emissions reductions affecting other source categories contained in their 1 hour ozone nonattainment area plans. This reduces the need to retrofit IC engines in those States.

In many cases, companies may use " early reductions"

achieved at IC engines due to other requirements, such as RACT. 51 For example, many IC engines were previously controlled to meet RACT requirements in many of the NOx SIP Call States. These emissions reductions help States meet their NOx budgets and, thus, decrease the amount of Draft   Do not cite, quote or distribute 52 " IC Engine OTAG Questions" document prepared by INGAA, February 17, 2000. Many of these engines are smaller than the " large" engines identified in the NOx SIP Call.

53 Alpha Gamma memo of June 19, 2002 ( Docket No. OAR 2001 0008, Item No. 0917).

54 See proposed rule at 67 FR 77845.

55 INGAA letter of July 16, 2002 ( Docket No. OAR 2001 0008, Item No. 0918).

173 additional reductions needed. According to information submitted by INGAA, a 1996 97 survey determined that 245 lean burn engines in the NOx SIP Call area have LEC. 52 Many engines in the NOx SIP Call area already have decreased NOx emissions at rich burn engines through non selective catalytic reduction( NSCR). 53 States may choose to credit these reductions instead of requiring new reductions at other engines in order to meet the SIP budget. Many more NOx reductions are likely to result from future maximum achievable control technology ( MACT) controls at IC engines. 54 These factors also reduce the need to retrofit IC engines in some States.

We agree with industry comments that pipeline companies will phase in the control equipment over a multi year timeframe. 55 Some companies may choose to stagger installation of the controls, beginning even before completion of our rulemaking. 2255 Stretching out the installation timeframe in this manner would help the Draft   Do not cite, quote or distribute 56 A top end overhaul is generally recommended between 8,000 and 30,000 hours of operation that entails a cylinder head and turbocharger rebuild ( see Table 4 from " Technology Characterization: Reciprocating Engines" prepared by Energy Nexus Group for EPA, 2 02).

57 GRI 12 98 report " NOx Control for Two Cycle Pipeline Reciprocating Engines," page 4 11. ( Docket No. OAR 2001 0008, Item No. XII K 24.)

174 companies achieve the results on time. Further, companies might choose to install controls early in some of their engines in a timeframe that coincides with the engine rebuild cycle. 56 In another case, installation of the LEC retrofit kit was estimated to span 3 to 4 weeks and the installation was not expected to impact the normal maintenance interval. 57 These approaches will help reduce the time needed to install the controls.

We believe the industry has demonstrated that multiple engines at compressor stations can be successfully retrofitted over a 24 month timeframe. For example, in Kentucky, the Jefferson Town Compressor Station's RACT compliance plan of April 2000 describes the installation of LEC using a phased approach over a 2 year period. Four engines were retrofitted during the summer of 2001 and the remaining five engines were retrofitted in the summer of 2002. Each engine was expected to be out of service for approximately 6 weeks and, due to heavy demand during the winter heating season, all engines were expected to be Draft   Do not cite, quote or distribute 58 See http:// www. enginuityinc. com 175 operable from October to April. Two additional cases show installation on multiple engines in short time periods.

Southern California Gas Company completed testing of one engine in 1995 and installed precombustion chambers on six engines in its Mojave Desert operating area. The conversion of the first unit was completed in October 1995 and the conversion of the sixth unit was completed in November 1996.

The engines met the 2.0 g/ bhp hr standard set by the Mojave Air District. Furthermore, as cited in a case study in Vidor, Texas, six engines in the Beaumont/ Port Arthur area were retrofitted in the summer of 1999.58 As shown below, we also examined historic timeframes allowed by the Congress and various regulatory agencies to achieve compliance with NOx requirements following State/ local rule adoption. These timeframes generally illustrate the successful implementation of past regulatory programs involving the installation of NOx controls.

In the 1990 Amendments to the CAA, Congress added RACT requirements for major sources of NOx. All categories of major NOx sources in certain areas of the nation were required to install RACT as expeditiously as practicable or no later than May 31, 1995. Thus, Congress allowed a maximum of 30 months from the SIP submittal deadline of Draft   Do not cite, quote or distribute 59 " Determination of RACT and BARCT for Stationary Spark Ignited Internal Combustion Engines, " California" California Air Resources Board, November 2001, pg. IV 15. ( Docket No. OAR 2001 0008, Item No. XII K 71.)

176 November 15, 1992 for a much larger number of sources than affected by this rulemaking.

Subsequent to the initial set of NOx RACT SIP revisions, we approved NOx RACT SIP submittals in some areas which had been exempt from the requirements. For example,

in Dallas, SIP rules required RACT as expeditiously as practicable or 24 months from the State adoption date ( rule adopted March 21, 1999). The State of Texas, on December 31, 1997, implemented a requirement for all major NOx sources in the Houston area to implement RACT; the State adopted a compliance date of November 15, 1999 for this program ( 22.5 months). In a recent case, the State of Louisiana allowed up to a 3 year period in Baton Rouge,

coinciding with their attainment deadline.

For engines subject to RACT limits, the California Air Resources Board guidance document on IC engines recommends final compliance within 2 years of district rule adoption. 59 The guidance states that this time period should be sufficient to evaluate control options, place purchase orders, install equipment, and perform compliance verification testing. The Sacramento Air District in California required compliance within 2 years of rule Draft   Do not cite, quote or distribute 177 adoption ( June 1995).

Regarding the need to obtain permits, we believe that States will process permits expeditiously, especially those permits associated with pollution control projects. We have specifically encouraged States in a recent memo ( see NSR exclusion discussion in section II. B. 2. c of this final rule)

to consider exempting pollution control projects from certain permitting requirements. Further, by moving the compliance date to at least 24 months after the SIP submittal date, we believe that the time needed to revise permits will not adversely affect the compliance schedule.

Further, the CAA contains an overarching principle that downwind areas attain the ozone NAAQS " as expeditiously as practicable." [ Sections 191( a), 172( a)]. The emissions reductions from today's rulemaking reflect the emissions reductions mandated under the NOx SIP Call in order to prevent significant contribution to nonattainment in downwind States. Thus, we are setting an implementation date that will assure that the downwind States realize the air quality benefits of NOx reductions in order to achieve attainment or reasonable further progress toward attainment ( 63 FR 57449 50).

Although we provided a compliance date of 1,309 days for Phase I sources from the SIP submittal date, we do not Draft   Do not cite, quote or distribute 178 believe that a similar compliance period is needed for the sources affected by today's rulemaking. This is because today's rulemaking affects a smaller subset of sources than Phase I sources, and whichthese sources have been aware of the applicability of the NOx SIP Call since 1998. In addition, as discussed earlier, States are free to choose which sources to regulate in compliance with the NOx SIP Call requirements. Also, some States have already adopted SIPs that meet the full NOx SIP Call requirements.

In summary, several factors described above will serve to minimize the number of large IC engines that would need to be scheduled for LEC retrofit. Further, companies that phase in compliance activities over several years would also reduce the number of IC engines needing LEC retrofit per year. It is important to note that RACT experience shows that companies can install LEC retrofit over a 2 year timeframe, even where multiple engines are located at the same compressor station. In recent RACT compliance time decisions, State/ local regulatory agencies generally specified 24 month periods to install controls. The Congress in its 1990 CAA Amendments allowed a maximum of 30 months for all major NOx sources across the nation to install RACT; this was a much larger task than installation of controls at IC engines in certain States. As a result, Draft   Do not cite, quote or distribute 179 we believe that a 2 year period after the SIP submittal due date is adequate for the installation of controls.

Further, because the NOx SIP Call is directed at emissions during the ozone season, we believe that the initial month where compliance is required should occur during the ozone season. Therefore, the compliance date is May 1, 2007 ( or, if later, the date on which the source commences operation).

3. What Compliance Date Are We Finalizing for Georgia and Missouri?

For all sources in Georgia and Missouri, we proposed a compliance date of May 1, 2005 ( or, if later, the date on which the source commences operation). This compliance date was based on a proposed SIP submittal deadline of April 1,

2003 and would have provided sources 25 months after SIP submittal to install controls. Based on the [ Insert date 12 months from signature date] SIP submittal deadline being finalized in today's final rule, providing sources with 25 months to install controls would result in a compliance deadline of September[ Insert date 30, 20067 months from signature]. Because this would be after the 2006 ozone season, we are finalizing a compliance deadline of May 1,

2007 ( or, if later, the date on which the source commences operation). As we explained in the NOx SIP Call, we believe Draft   Do not cite, quote or distribute 180 a 25 month compliance time frametimeframe is reasonable given the amount of controls that need to be installed. If Missouri and/ or Georgia elect to control large EGUs under a trading program, we project that the most time  consuming control installation will require installation of two SCRs and one SNCR. We also project that this can be done in 25 months ( 67 FR 8395).

Several commenters suggested that a May 1, 2005 compliance date was reasonable for Georgia and Missouri if the rule were finalized in time to give States 1 year to develop a regulation and SIPs were due by April 1, 2003.

One commenter added that many EGUs will be installing controls before 2005 in order to comply with a State ozone attainment plan. We agree that the proposed compliance deadline was reasonable when it was proposed. However, we are adopting a May 1, 2007 compliance deadline to take into account the delay in finalizing today's rule.

One commenter suggested that providing units in Georgia and Missouri 25 months to comply was not enough time. This commenter provided documentation from an engineering firm suggesting that it would take at least 36 months to install SCR on one unit. The commenter further asserted that it would take even longer to install SCR on two units at a single plant and suggested that Missouri sources be given at Draft   Do not cite, quote or distribute 181 least 43 months to install controls. We disagree with this commenter. Many SCR projects have been completed in significantly less time. For instance, an SCR was installed on the AES Somerset Plant in New York in 9 months from contract award to completion. Reliant Energy completed construction of two SCRs on two 900 MW units at their Keystone Plant in Pennsylvania in 46 weeks. Even assuming that the engineering and permitting took a year, this job was completed in less than 24 months. It should also be noted that this job was completed in 2003. This was part of the peak construction period for SCRs under Phase I of the NOx SIP Call. Projects in Georgia and Missouri, being constructed after the bulk of the SCRs for the NOx SIP Call have been installed, should have much less competition for resources. The commenter provided no explanation of why this project should take so long when so many other projects have been completed in less time. Furthermore, the NOx SIP Call provides Missouri with CSP allowances that Missouri may use to address situations when installation cannot be completely finished by the compliance date. It should also be noted that while we believe that the SCRs can be installed within 25 months, if Missouri completes its SIP by December 31, 2005, they will actually have 29 months to install the SCRs. This assumes that the company does not Draft   Do not cite, quote or distribute 182 begin any work on the SCRs until after the SIP is finalized.

Since the company should have a strong indication as to whether they will need to install the SCRs before the SIP is completed, they will actually have more than 29 months to install the SCRs.

L. What Action Are We Taking on Wisconsin?

In Michigan, the Wisconsin industry petitioners argued that the emissions from Wisconsin do not contribute significantly to nonattainment in any other State. Section 110( a)( 2)( D)( i)( I) requires that a State " contribute significantly to nonattainment in ... any other State" in order to be included in the challenged NOx SIP Call. 42 U. S. C. 7410( a)( 2)( D)( i)( I). The Court held that " EPA erroneously included Wisconsin in the NOx SIP Call because EPA failed to explain how Wisconsin contributes to nonattainment in any other State," Michigan, 213 F. 3d at 681 ( emphasis in original). The Court noted that the record showed only that emissions from Wisconsin contribute to violations of the standard over Lake Michigan.

Our " zero out" modeling of Wisconsin emissions using UAM V shows that emissions from Wisconsin impact ozone levels in neighboring States, but not during exceedances of the 1 hour NAAQS ( i. e., these impacts occur when ozone levels are below the NAAQS). For the OTAG episodes we Draft   Do not cite, quote or distribute 183 modeled, the ozone impacts of Wisconsin on 1 hour nonattainment are predicted in the northwestern part of Lake Michigan near the shore line of Wisconsin. In the NOx SIP Call rulemaking, we concluded that impacts over the lake should be considered as contributions to States bordering the lake ( i. e., Michigan, Indiana, and Illinois) because of lake breeze effects ( 63 FR 57386, October 27, 1998). The Court found that we had not provided adequate support for this determination and vacated the rule's application to Wisconsin for the 1 hour standard. Michigan, 213 F. 3d at 681.

We agree that additional modeling would be necessary in order to find that Wisconsin significantly contributes to downwind 1 hour nonattainment in any other State and to include Wisconsin in the NOx SIP Call at this time. We do not currently have the modeling necessary to take such action, therefore, we are excluding the entire State of Wisconsin from the requirements of the 1 hour basis of the NOx SIP Call to conform to the Court's decision. In addition, we received only one comment on excluding Wisconsin from the NOx SIP Call and it supported our proposal to do so.

We are not, however, determining that Wisconsin's emissions do not contribute significantly to nonattainment Draft   Do not cite, quote or distribute 184 downwind. We have not completed the additional modeling analysis for the States that are part of the OTAG region but were not included in the final NOx SIP Call. Although we stayed the 8 hour basis of the NOx SIP Call Rule on September 18, 2000 ( 65 FR 56245), we are in the process of evaluating lifting the stay. Today's action to exclude Wisconsin from the 1 hour basis of the NOx SIP Call does not address whether Wisconsin should remain subject to the 8

hour basis of the NOx SIP Call. We will address that issue at the time we lift the stay as it applies to Wisconsin.

M. How Are the 8 hour Ozone NAAQS Rules Affected by tThis Action?

As noted above, the revisions to the NOx SIP Call in today's action respond to the Court's decision in Michigan.

The Court's decision and today's action concern issues arising under only the 1 hour ozone NAAQS, and not the 8

hour ozone NAAQS. Accordingly, none of the actions finalized today   the definitions of EGU and non EGU and the control requirements for IC engines, and implications for the State budgets; the SIP submission dates; compliance dates; the revised emissions budgets for Alabama, Georgia,

Michigan, and Missouri; and the exclusion of Wisconsin   have any effect on any requirements of the NOx SIP Call on States under the 8 hour ozone NAAQS. Because of the Draft   Do not cite, quote or distribute 185 litigation concerning the 8 hour ozone NAAQS, we stayed all of the requirements of the NOx SIP Call under the 8 hour ozone NAAQS, ranging from the SIP submission dates to the control requirements ( 65 FR 56245, September 18, 2000).

Since then, the Supreme Court has held that the CAA authorizes EPA to revise the ozone NAAQS. Whitman v.

American Trucking Ass'ns., 121 S. Ct. 903 ( 2001). At this time, we are evaluating the process for lifting the 8 hour stay.

N. What Modifications Are Being Made to Parts 78 and 97?

51, 78, and 97?

Today's action makes certain modifications to 40 CFR Part 51, the implementing regulations for the NOx SIP Call Rule, that were promulgated on October 28, 1998. These modifications, which include clarifications, definitions,

and minor changes, are being made in response to the various court decisions on the NOx SIP Call, ( Michigan v. EPA, 213 F. 3d 663 ( D. C. Cir. 2000), cert denied, 121 S. Ct. 1225 ( 2001)), the NOx SIP Call Technical Amendments ( Appalachian Power v. EPA, 251 F. 3d 1026 ( D. C. Cir. 2001)), and the Section 126 Rule ( Appalachian Power v. EPA, 249 F. 3d 1042 ( D. C. Cir. 2001)).

In response to the court decision in Michigan, the Agency divided the NOx SIP Call into two phases ( Phase I and Draft   Do not cite, quote or distribute 186 Phase II), thereby enabling the Agency to proceed with those portions of the NOx SIP Call that were upheld by the Court.