Draft   Do not cite, quote or distribute 6560 50 P ENVIRONMENTAL PROTECTION AGENCY 40 CFR Parts 51, 52, 78, 96, and 97 [ FRL ] RIN 2060 AJ16 Interstate Ozone Transport: Response to Court Decisions on the NOx SIP Call, NOx SIP Call Technical Amendments, and Section 126 Rules AGENCY: Environmental Protection Agency ( EPA).

ACTION: Final rule.

SUMMARY: In today's action, EPA is establishing the final full nitrogen oxides ( NOx) budgets for States subject to the NOx State implementation plan ( SIP) Call. This final rule requires States that submitted SIPs to meet the Phase I NOx SIP Call budgets to submit Phase II SIP revisions as needed to achieve the necessary incremental reductions of NOx. It also requires Georgia and Missouri to submit SIP revisions meeting the full NOx SIP Call budgets since they were not required to submit Phase I SIPs. These SIPS are necessary to prohibit specified amounts of emissions of NOx   one of the precursors to ozone ( smog) pollution   for the purposes of reducing NOx and ozone transport across State boundaries in the eastern half of the United States.

In today's action, we are amending two related final Draft   Do not cite, quote or distribute 3 rules we issued under sections 110 and 126 of the Clean Air Act ( CAA) related to interstate transport of NOx. We are responding to the March 3, 2000 decision of the United States Court of Appeals for the District of Columbia Circuit ( D. C. Circuit) in which the Court largely upheld the NOx SIP Call, but remanded four narrow issues to us for further rulemaking action; the related decision by the D. C. Circuit on June 8, 2001, concerning the rulemakings providing technical amendments to the NOx SIP Call in which the Court,

among other things, vacated and remanded an issue for further rulemaking; and the decision by the D. C. Circuit on May 15, 2001, concerning the related Section 126 rulemaking in which the Court, among other things, vacated and remanded an issue for further rulemaking; and the related decision by the D. C. Circuit on August 24, 2001, concerning the Section 126 Rule, in which the Court remanded an issue.

We are also taking final action on modifications that were proposed on June 13, 2001 to the Appeal Procedures and to the Federal NOx Budget Trading Program. Today's final rule completes action on the June 13, 2001 proposed rule revisions for sources subject to the Federal NOx Budget Trading Program under the sSection 126 final rule.

The specific issues addressed in this action are described below under SUPPLEMENTARY INFORMATION. Draft   Do not cite, quote or distribute 4 DATES: This rule is effective [ insert date 60 days after publication].

FOR FURTHER INFORMATION CONTACT: General questions concerning today's action should be addressed to Jan King,

Office of Air Quality Planning and Standards, Air Quality Strategies and Standards Division, C539 02, Research Triangle Park, NC, 27711, telephone ( 919) 541 5665, e mail king. jan@ epa. gov. Technical questions concerning electric generating units ( EGUs) should be directed to Kevin Culligan, Office of Atmospheric Programs, Clean Air Markets Division, ( 6204M), 1200 Pennsylvania Ave., NW, Washington,

DC 20460, telephone ( 202) 564 9172, e mail culligan. kevin@ epa. gov; technical questions concerning stationary internal combustion ( IC) engines should be directed to Doug Grano, Office of Air Quality Planning and Standards, C539 02, Research Triangle Park, North Carolina 27711, telephone ( 919) 541 3292, e mail grano. doug@ epa. gov;

legal questions should be directed to Winifred Okoye, Office of General Counsel, ( 2344A), 1200 Pennsylvania Ave., NW,

Washington, DC 20460, telephone ( 202) 564 5446, e mail okoye. winifred@ epa. gov.

SUPPLEMENTARY INFORMATION:

Today's action addresses the issues remanded or vacated Draft   Do not cite, quote or distribute 5 by the D. C. Circuit in Michigan v. EPA, 213 F. 3d 663 ( D. C.

Cir., 2000), cert. denied, 121 S. Ct. 1225, 149 L. ED. 135 ( 2001), which concerned the NOx SIP Call ( the " SIP Call case"); Appalachian Power v. EPA, 251 F. 3d 1026 ( D. C. Cir.

2001), which concerned the technical amendments rulemakings for the NOx SIP Call ( the " Technical Amendments case"); and Appalachian Power v. EPA, 249 F. 3d 1042 ( D. C. Cir. 2001).

Today's action establishes the second phase or Phase II of the NOx SIP Call by:

( 1) finalizing the definition of EGU as applied to certain small cogeneration units,

( 2) setting the control levels for stationary internal combustionIC engines,

( 3) excluding portions of Georgia, Missouri, Alabama and Michigan from the NOx SIP Call,

( 4) revising statewide emissions budgets in the NOx SIP Call to reflect the disposition of the first three issues above,

( 5) setting a SIP submittal date,

( 6) setting the compliance date for implementation of control measures, and ( 7) excluding Wisconsin from NOx SIP Call requirements.

For more detailed discussions of the issues addressed in this action, see section II below. Draft   Do not cite, quote or distribute 6 Ground level ozone has long been recognized to affect public health. Ozone induces health effects, including decreased lung function ( primarily in children active outdoors), increased respiratory symptoms ( particularly in highly sensitive individuals), increased hospital admissions and emergency room visits for respiratory causes ( among children and adults with pre existing respiratory disease such as asthma), increased inflammation of the lungs, and possible long term damage to the lungs. Each year,

groundlevel ozone is also responsible for crop yield losses.

Ozone also causes noticeable foliar damage in many crops,

trees, and ornamental plants ( i. e., grass, flowers, shrubs,

and trees) and causes reduced growth in plants. Studies indicate that current ambient levels of ozone are responsible for damage to forests and ecosystems ( including habitat for native animal species).

Availability of Related Information We have established an official public docket for this action under Docket ID No. OAR 2001 0008; it has also been incorporated by reference in the docket for the Section 126 Rule under Docket ID No. OAR 2001 20009. The official public docket consists of the documents specifically referenced in this action, any public comments received, and other information related to this action. Although a part Draft   Do not cite, quote or distribute 7 of the official docket, the public docket does not include Confidential Business Information ( CBI) or other information whose disclosure is restricted by statute. The official public docket is the collection of materials that is available for public viewing at the Air Docket in the EPA Docket Center, EPA West Building, Room B102, 1301 Constitution Ave., NW, Washington, DC. The Docket telephone number is ( 202) 566 1742; fax ( 202) 566 1741. The EPA Docket Center Public Reading Room is open from 8: 30 a. m. to 4: 30 p. m., Monday through Friday, excluding legal holidays.

The telephone number for the Reading Room is ( 202) 566 1744.

A reasonable fee may be charged for copying.

You may access this Federal Register document electronically through the EPA Internet under the " Federal Register" listings at http:// www. epa. gov/ fedrgstr/. An electronic version of the public docket is available through EPA's electronic public docket and comment system, EPA Dockets. You may use EPA Dockets at http:// www. epa. gov/ edocket/ to view public comments, access the index listing of the contents of the official public docket, and to access those documents in the public docket that are available electronically. Although not all docket materials may be available electronically, you may still access any of the publicly available docket materials Draft   Do not cite, quote or distribute 8 through the docket facility identified above. Once in the system, select " search," then key in the appropriate docket identification number.

Public Hearing We held a public hearing in Washington D. C. on March 15, 2002. Four people presented comments at the hearing.

The public also had an opportunity to submit written testimony within approximately 45 days after the hearing date.

Outline I. Background A. What Was Contained in the NOx SIP Call? B. What Were the Court Decisions on the NOx SIP Call? 1. What Was the Decision of the Court on the 8 Hour8 hour Ozone NAAQS? 2. What Effect Did The Court Decision Have on the 8 Hour Portion of the NOx SIP Call? 3. What Was the D. C. Circuit Decision on the Stay of the SIP Submittal Schedule for the NOx SIP Call? 4. What Was the Court's Decision on the NOx SIP Call? 5. How Did the Court Respond to Our Request to Lift the Stay of the 1 Hour SIP Submission Schedule? 6. What Was the Court's Order for the Compliance Date? C. What Was Contained in the Section 126 Rule? 1. What Was the D. C. Circuit Decision on the Section 126 Rule? D. What Were the Technical Amendments Rulemakings? 1. What Was the D. C. Circuit Decision on the Technical Amendments? E. What is the Overview of D. C. Circuit Remands/ Vacaturs? F. What is Our Process for Addressing the Remands/ Vacaturs?

II. What is the Scope of this Action? A. How Do We Treat Cogeneration Units and Non Acid Rain Units? 3. What is the Historical Definition of Utility Unit? Draft   Do not cite, quote or distribute 9 4. What Was the NOx SIP Call Definition of EGU? 5. What is the Rationale for the Final Rule's Treatment of Cogeneration Units? 6. What Revisions Are Being Made to the Definition of EGU in the NOx SIP Call and the Section 126 Rule? 7. What is the Effect on Cogeneration Unit Classification of Applying " One Third Potential Electrical Output Capacity/ 25 MWe Sales" Criteria, Rather Than the Same Methodology as Used for Other Units? B. What Are the Control Levels and Budget Calculations for Stationary Reciprocating Internal Combustion Engines ( IC Engines)? 1. Determination of Highly Cost Effective Reductions and Budgets 2. What Are the Key Comments We Received Regarding IC Engines? C. What is Our Response to the Court Decision on Georgia and Missouri? D. What Are We Finalizing for Alabama and Michigan in Light of the Court Decision on Georgia and Missouri? E. What Modifications Are Being Made to the NOx Emissions Budgets? F. How Will the Compliance Supplement Pools Be Handled? G. Will the EGU Budget Changes Affect the States Included in the Three State Memorandum of Understanding? H. How Does the Term " Budget" Relate to Conformity Budgets? I. How Will Partial State Trading Be Administered? 1. How Will Flow Control Be Handled for Georgia and Missouri? J. What Is the Phase II SIP Submittal Date? K. What Are the Phase II Compliance Dates? 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? 2. What ComplinaceCompliance Date Are We Finalizing for IC Engines and What is the Technical Feasibility of This Date? 3. What Compliance Date Are We Finalizing for Georgia and Missouri? L. What Action Are We Taking on Wisconsin? M. How Are the 8 Hour8 hour Ozone NAAQS Rules Affected by This Action? N. What Modifications Are Being Made to Parts 51, 78, and 97? Draft   Do not cite, quote or distribute 10 III. Statutory and Executive Order Reviews O. Executive Order 12866: Regulatory Planning and Review B. Paperwork Reduction Act C. Regulatory Flexibility Act D. Unfunded Mandates Reform Act E. Executive Order 13132: Federalism F. Executive Order 13175: Consultation and Coordination with Indian Tribal Governments G. Executive Order 13045: Protection of Children from Environmental Health and Safety Risks H. Executive Order 13211: Actions That Significantly Affect Energy Supply, Distribution, or Use I. National Technology Transfer Advancement Act J. Executive Order 12898: Federal Actions to Address Environmental Justice in Minority Populations and Low Income Populations K. Congressional Review Act I. BACKGROUND A. What Was Contained in the NOx SIP Call?

By notice dated October 27, 1998 ( 63 FR 57356), we took final action to prohibit specified amounts of emissions of one of the main precursors of ground level ozone, NOx, in order to reduce ozone transport across State boundaries in the eastern half of the United States. Based on extensive air quality modeling and analyses, we found that sources in 22 States and the District of Columbia ( D. C.) ( 23 States)

emit NOx in amounts that significantly contribute to nonattainment of the 1 hour ozone national ambient air quality standards ( NAAQS) in downwind States. We set forth requirements for each of the affected upwind States to submit SIP revisions prohibiting those amounts of NOx emissions which significantly contribute to downwind air Draft   Do not cite, quote or distribute 11 quality problems. We established statewide NOx emissions budgets for the affected States. The budgets were calculated by assuming the emissions reductions that would be achieved by applying available, highly cost effective controls to source categories of NOx. States have the flexibility to adopt the appropriate mix of controls for their State to meet the NOx emissions reductions requirements of the NOx SIP Call. A number of parties,

including certain States as well as industry and labor groups, challenged our NOx SIP Call Rule.

Independently, we also found that sources and emitting activities in 22 States and the District of Columbia emit NOx in amounts that significantly contribute to nonattainment of the 8 hour ozone NAAQS. In response to the court decisions, on September 18, 2000 ( 65 FR 56245), we stayed the findings in the NOx SIP Call based on the 8 hour ozone NAAQS. However, we are evaluating the process for lifting the stay in light of recent EPA actions on the 8

hour ozone standard.

B. What Were the Court Decisions on the NOx SIP Call?

1. What Was the Decision of the Court on the 8 Hour8 hour Ozone NAAQS?

On May 14, 1999, the D. C. Circuit issued an opinion which, in relevant parts, questioned the constitutionality Draft   Do not cite, quote or distribute 12 of the CAA as applied by EPA in its 1997 revision of the ozone NAAQS. See American Trucking Ass'n v. EPA, 175 F. 3d 1027 ( D. C. Cir., 1999). The Court's ruling curtailed our ability to require States to comply with a more stringent ozone NAAQS.

On October 29, 1999, the D. C. Circuit granted in part and denied in part our rehearing request. American Trucking Ass'n v. EPA, 194 F. 3d 4 ( D. C. Cir. 1999). In May 2000, the Supreme Court granted our petition and certain petitioners'

cross petitions of certiorari. On February 27, 2001, the Supreme Court handed down its decision in Whitman v.

American Trucking Association, 531 U. S. 457 ( 2001). In vacating the D. C. Circuit's holding on the point, the Supreme Court held that the CAA was not unconstitutional in its delegation of authority for us to promulgate a revised ozone NAAQS. The case was remanded to the D. C. Circuit to consider challenges to the revised ozone NAAQS on other grounds.

2. What Effect Did the Court Decision Have on the 8 hour Portion of the NOx SIP Call?

The litigation created uncertainty with respect to our ability to rely upon the 8 hour ozone standards as an alternative basis for the NOx SIP Call. As a result, we stayed indefinitely the findings of significant contribution Draft   Do not cite, quote or distribute 13 based on the 8 hour standard, pending further developments in the NAAQS litigation ( 65 FR 56245, September 18, 2000).

Because the NOx SIP Call Rule was based independently on the 1 hour standards, a stay of the findings based on the 8 hour standards had no effect on the remedy required by the 1998 NOx SIP Call. That is, the stay does not affect our findings based on the 1 hour standards.

3. What Was the D. C. Circuit Decision on the Stay of the SIP Submittal Schedule for the NOx SIP Call?

The NOx SIP Call Rule required States to submit SIP revisions by September 30, 1999. State petitioners challenging the NOx SIP Call filed a motion requesting the Court to stay the submission schedule until April 27, 2000.

In response, the D. C. Circuit issued a stay of the SIP submission deadline pending further order of the Court.

Michigan v. EPA, 213 F. 3d 663 ( D. C. Cir. 2000) ( May 25, 1999 order granting stay in part).

4. What Was the Court's Decision on the NOx SIP Call?

On March 3, 2000, the D. C. Circuit issued its decision on the NOx SIP Call, ruling in our favor on the issues that affected the rulemaking as a whole, but ruling against us on several issues. Michigan v. EPA, 213 F. 3d 663 ( D. C. Cir.

2000). The Court's decision in Michigan v. EPA, 213 F. 3d 663 ( D. C. Cir. 2000) concerns only the 1 hour basis for the Draft   Do not cite, quote or distribute 14 NOx SIP Call, and not the 8 hour basis. The requirements of the NOx SIP Call, including the findings of significant contribution by the 23 States, the emissions reductions that must be achieved, and the requirement for States to submit SIPs meeting statewide NOx emissions reductions requirements, are fully and independently supported by our findings under the 1 hour NAAQS alone. The Court denied petitioners' requests for rehearing or rehearing en banc on July 22, 2000. Specifically, the Court found in our favor on the following claims:

( 1) we could call for the SIP revisions without convening a transport commission;

( 2) we undertook a sufficiently State specific determination of ozone contribution;

( 3) we did not unlawfully override past precedent regarding " significant" contribution;

( 4) our consideration of the cost of NOx emissions reductions as part of the determination of significant contribution is consistent with the statute and judicial precedent;

( 5) our scheme of uniform emissions reductions requirements is reasonable;

( 6) our interpretation of CAA section 110( a)( 2)( D)( i)( I) does not violate the Draft   Do not cite, quote or distribute 15 nondelegation doctrine;

( 7) we did not intrude on the statutory rights of States to fashion their SIPs;

( 8) we properly included South Carolina in the NOx SIP Call; and ( 9) we did not violate the Regulatory Flexibility Act ( RFA).

However, the Court ruled against us on four specific issues. Specifically, the Court:

( 1) remanded and vacated the inclusion of Wisconsin because emissions from Wisconsin did not show a significant contribution to downwind nonattainment of the NAAQS;

( 2) remanded and vacated the inclusion of Georgia and Missouri in light of the Ozone Transport Assessment Group ( OTAG) conclusions that emissions from coarse grid portions did not merit controls;

( 3) held that we failed to provide adequate notice of the change in the definition of EGU as applied to cogeneration units that supply electricity to a utility power distribution system for sale in amounts of either one third or less of their potential electrical output capacity or 25 megawatts or less per year ( small cogeneration Draft   Do not cite, quote or distribute 16 units); and ( 4) held that we failed to provide adequate notice of the change in control level assumed for large stationary IC engines.

The Court remanded the last two matters for further rulemaking.

5. How Did the Court Respond to Our Request to Lift the Stay of the 1 Hour SIP Submission Schedule?

On April 11, 2000, we filed a motion with the Court to lift the stay of the SIP submission date. We requested that the Court lift the stay as of April 27, 2000. We recognized, however, that at the time the stay was issued,

States had approximately 4 months ( 128 days) remaining to submit SIPs. Therefore, our motion to lift the stay indicated that we would allow States until September 1, 2000 to submit SIPs addressing the NOx SIP Call and provided that States could submit only those portions of the NOx SIP Call upheld by the Court ( Phase I SIPs). The existing record in the NOx SIP Call rulemaking provides a breakdown of the data on which the original budgets were developed sufficient to allow States to develop Phase I SIPs. However, we reviewed the record and for the convenience of the States and in letters to the State Governors and State Air Directors,

dated April 11, 2000, we identified an adjusted Phase I NOx Draft   Do not cite, quote or distribute 1 October 30, 2000 was the first business day following the expiration of the 128 day period.

17 budget for each State for which the NOx SIP Call applies.

On June 22, 2000, the Court granted our request in part. The Court ordered that we allow the States 128 days from the June 22, 2000 date of the order to submit their SIPs. Therefore, SIPs in response to the NOx SIP Call were due October 30, 2000.1 In our motion to lift the stay, we informed the Court that the Agency asked 19 States and the District of Columbia, in letters to the Governors dated April 11, 2000,

to submit SIPs subject to the Court's response to our motion to lift the stay. The 19 States are: Alabama, Connecticut,

Delaware, Illinois, Indiana, Kentucky, Massachusetts,

Maryland, Michigan, North Carolina, New Jersey, New York,

Ohio, Pennsylvania, Rhode Island, South Carolina, Tennessee,

Virginia and West Virginia. Rather than submit a SIP that fully met the NOx SIP Call, we allowed these 19 States and the District of Columbia to submit SIPs that cover all of the NOx SIP Call requirements except for a small part of the EGU portion and large IC engine portions of the budget. We refer to these partial plans that addressed the portion of the rule unaffected by the Court's remand as the " Phase I" Draft   Do not cite, quote or distribute 2 The Phase I emissions reductions should achieve approximately 90 percent of the total emissions reductions called for by the NOx SIP Call.

18 SIPs. 2 Because the NOx SIP Call was vacated with respect to Georgia, Missouri, and Wisconsin, those States were not obligated to submit any SIPs by October 30, 2000. The SIPs that cover the portion of the rule affected by the Court decision   and the subject of today's action   are termed,

the " Phase II" SIPs.

6. What Was the Court's Order for the Compliance Date?

In response to a motion filed by the industry/ labor petitioners, on August 30, 2000, the D. C. Circuit ordered that the court order filed on June 22, 2000 be amended to extend the deadline for full implementation of the NOx SIP Call from May 1, 2003 to May 31, 2004. This extension was calculated in the same manner used by the Court in extending the deadline for SIP submissions, so that sources in States subject to the NOx SIP Call would have 1,309 days for implementing the SIP as provided in the original NOx SIP Call.

C. What Was Contained in the Section 126 Rule?

We have also addressed interstate NOx transport in a final rule ( Section 126 Rule) that responds to petitions submitted by eight Northeast States under section 126 of the Draft   Do not cite, quote or distribute 3 For Indiana, Kentucky, Michigan, and New York, only sources in portions of the State are affected by that rule.

4 The Section 126 Rule uses the same definition of EGUs that we are finalizing for the NOx SIP Call in today's action.

5 As discussed in the next section, on August 24, 2001, the D. C. Circuit suspended the compliance date for EGUs while we resolved a remanded issue related to EGU growth factors. We published our response to the growth factor issue on May 1, 2002 ( 67 FR 21868).

19 CAA ( 65 FR 2674, January 18, 2000)( the Section 126 Rule).

In this rule, we made findings that 392 sources in 12 States and the District of Columbia are significantly contributing to 1 hour ozone nonattainment problems in the petitioning States of Connecticut, Massachusetts, New York, and Pennsylvania. The upwind States with sources affected by the Section 126 Rule are: Delaware, Indiana, Kentucky,

Maryland, Michigan, North Carolina, New Jersey, New York,

Ohio, Pennsylvania, Virginia, West Virginia, and the District of Columbia. 3 The types of sources affected are large EGUs4 and large industrial boilers and turbines ( non

EGUs). The rule established Federal NOx emissions limits for the affected sources and set a May 1, 2003 compliance date. 5 We promulgated a NOx cap and tradecap and trade program as the control remedy. All of the sources affected by this Section 126 Rule are located in States that are subject to the NOx SIP Call. Draft   Do not cite, quote or distribute 20 The Section 126 Rule includes a provision to coordinate the Section 126 Rule with State actions under the NOx SIP Call. This provision automatically withdraws the Section 126 findings and control requirements for sources in a State if the State submits, and we give final approval to, a SIP revision meeting the full NOx SIP Call requirements,

including the originally promulgated May 1, 2003 compliance deadline [ 40 CFR 52.34( i)]. The Court changed the NOx SIP Call compliance deadline to May 31, 2004 after we had promulgated and justified the automatic withdrawal provision based on approval of a SIP with a May 1, 2003 compliance date ( 64 FR 28274 76, May 25, 1999; 65 FR 2679 2684, January 18, 2000). As described below, as the result of a court decision, the Section 126 Rule was delayed. On April 30,

2002, we published, " Section 126 Rule: Revised Deadlines;

Final Rule," ( 67 FR 21522) which reset the compliance date and other related dates, such as the monitoring certification date. The new compliance date is May 31,

2004. This action harmonized the dates in the Section 126 Rule with those in the NOx SIP Call.

On April 30, 2002, we published a proposal to revise the Section 126 Rule withdrawal provision so that it would continue to function based on the new compliance dates and Draft   Do not cite, quote or distribute 21 on a Phase I SIP ( 67 FR 21522).

1. What Was the D. C. Circuit Decision on the Section 126 Rule?

On May 15, 2001, a panel of the D. C. Circuit largely upheld the Section 126 Rule in Appalachian Power v. EPA, 249 F. 3d 1032 ( 2001). ( Appalachian Power   Section 126).

However, the Court remanded the method for determining growth to the year 2007 in heat input utilization by EGUs.

This calculation is important for determining the requirements for EGUs. In addition, the Court vacated and remanded to us the portion of the rule classifying as EGUs small cogeneration units. Although in the Michigan decision ( concerning the NOx SIP Call rulemaking), the D. C. Circuit remanded this issue on the procedural ground of inadequate notice, in the Appalachian Power   Section 126 decision, the Court vacated and remanded on grounds that we did not justify our classification of small cogeneration units as EGUs. In an order dated August 24, 2001, the D. C. Circuit,

in Appalachian Power   Section 126 Case, remanded the Section 126 Rule with regard to the classification of any cogeneration units as EGUs and tolled ( suspended) the date for EGUs to implement controls pending our resolution of the EGU growth factor remand. Draft   Do not cite, quote or distribute 22 During the course of the litigation on the Section 126 Rule, individual sources or groups of sources challenged the rule on grounds that our allocations of allowances were improper. We resolved these cases with several of those sources with our agreement to propose a rulemaking revising the allocations.

D. What Were the Technical Amendments Rulemakings?

When we promulgated the NOx SIP Call Rule, we decided to reopen public comment on the source specific data used to establish each State's 2007 EGU budget ( 63 FR 57427, October 28, 1998). We extended this comment period by notice dated December 24, 1998 ( 63 FR 71220). We indicated that we would entertain requests to correct the 2007 EGU budgets to take into account errors or updates in some of the underlying emissions inventory and certain other specified data.

Following our review of the comments received, we published a rulemaking providing Technical Amendments to,

among other things, the 2007 EGU budgets ( 64 FR 26298, May 14, 1999). In response to additional comments received, we published a second rulemaking, making additional Technical Amendments to the 2007 EGU budgets ( 65 FR 11222, March 2,

2000). ( These two rulemakings may be referred to, together,

as the Technical Amendments Rule.) In promulgating the Draft   Do not cite, quote or distribute 23 Technical Amendments Rule, we kept intact our method for determining the budgets, including the methods for determining growth to 2007. We simply made adjustments for particular sources concerning whether they were large EGUs or non EGUs, and adjustments in the appropriate baselines for those sources.

1. What Was the D. C. Circuit Decision on the Technical Amendments?

On June 8, 2001, the D. C. Circuit issued its opinion in a case involving the Technical Amendments. Appalachian Power v. EPA, 251 F. 3d 1026 ( D. C. Cir. 2001). ( Appalachian Power   Technical Amendments). Although largely upholding the Technical Amendments, the court, as in the Appalachian Power   Section 126 case, remanded the EGU growth factors and vacated and remanded the portion of the rule classifying small cogeneration units as EGUs. In addition, in the Appalachian Power Technical Amendments decision, the Court remanded and vacated the budget under the Technical Amendments Rule for Missouri under both the 1 hour and 8

hour ozone NAAQS.

E. What is the Overview of D. C. Circuit Remands/ Vacaturs?

In summary, the D. C. Circuit decisions described above Draft   Do not cite, quote or distribute 24 revised or remanded/ vacated portions of the NOx SIP Call,

Section 126, and Technical Amendments rulemakings as follows:

( 1) remanded the portion of the NOx SIP Call requirements based on the assumed control level for stationary IC engines;

( 2) delayed the NOx SIP Call SIP submittal date to October 30, 2000. Michigan;

( 3) delayed the date for implementation of the NOx SIP Call reductions to May 31, 2004. Michigan;

( 4) remanded and vacated the inclusion of Wisconsin.

Michigan;

( 5) remanded and vacated the NOx SIP Call budgets for Georgia and Missouri under the 1 hour ozone NAAQS.

Michigan;

( 6) remanded and vacated the NOx SIP Call budget, as revised by the Technical Amendments, for Missouri,

under the 1 hour and 8 hour ozone NAAQS. Appalachian Power   Technical Amendments;

( 7) remanded the EGU growth formula. Appalachian Power   Section 126, Appalachian Power   Technical Amendments;

( 8) remanded, or remanded and vacated, the classification Draft   Do not cite, quote or distribute 25 of small cogeneration units as EGUS. Michigan,

Appalachian Power Section 126, Appalachian Power   Technical Amendments; and ( 9) remanded the classification of any cogeneration units as EGUs. Appalachian Power Section 126.

F. What is Our Process for Addressing the Remands/

Vacaturs?

To date, we have responded to these decisions as followsdetailed below:

In letters dated April 11, 2000, to the Governors of the affected States, we advised that the States may submit by October 30, 2000 Phase I SIPs that include a budget allowing more emissions than under the NOx SIP Call Rule.

This budget need not include any reductions from a set of EGUs that we believe includes all of the small cogeneration units or reductions from stationary IC engines. In addition, we advised Wisconsin that it need not submit a NOx SIP Call SIP revision. Further, we advised Georgia and Missouri that they did not have to submit NOx SIP Call SIPs at this time. We advised Alabama and Michigan that although the Court upheld the NOx SIP Call for their entire States,

the reasoning of the Court's opinion concerning Georgia and Missouri supported excluding emissions from the coarse grid Draft   Do not cite, quote or distribute 6 All required States have submitted final SIPs. We have published final approval for 156 States and the District of Columbia. We have published final conditional approvals for two States.

26 portion of their States. We also stated that if they wanted the coarse grid portion of their States excluded, they could submit a Phase I budget addressing sources in only the finegrid portion of the State. All States were further advised that the remanded issues would be addressed in a future rulemaking.

Many States did not officially submit complete SIPs as required by October 30, 2000. By notice dated December 26,

2000 ( 65 FR 81366), we issued findings of failure to submit. 6 All required States have now submitted complete Phase I SIPs and the sanctions clocks have effectively been turned off.

On February 22, 2002, we proposed our response to the court decisions described above, except for the EGU growth remand. Today's action finalizes the second phase or Phase II of the NOx SIP Call by addressing the remanded and vacated issues as described above. In addition, we are modifying the budgets for Alabama and Michigan based on inclusion of only the fine grid portion of those States.

Further, we are excluding Wisconsin from the 1 hour basis of Draft   Do not cite, quote or distribute 27 the NOx SIP Call.

Any additional emissions reductions required as a result of this rulemaking are reflected in the Phase II portion of the State's emissions budget. The emissions reductions required in Phase II are relatively small,

representing less than 10 percent of total reductions required by the NOx SIP Call. Partial State budgets for Georgia and Missouri and the due date for the SIPs meeting the resulting State emissions budgets (" Phase II" SIPs) are discussed below in sections II. E and II. J, respectively.

Today's rulemaking does not address the EGU growth remand. We responded to that issue in an action entitled,

" Response to Court Remand on NOx SIP Call and Section 126 Rule," which was published in the Federal Register on May 1,

2002 ( 67 FR 21868). Our response to the growth remand was challenged in the D. C. Circuit. All parties filed briefs in May 2003 and oral argument is scheduled forwas held on September 15, 2003. The Agency expects a decision by the Court in the January to March 2004 timeframe.

Today's rulemaking does not address NOx SIP Call or Section 126 Rule issues related to the 8 hour ozone NAAQS.

WhileAlthough we had stayed the findings inon the NOx SIP Call based on the 8 hour NAAQS ( 65 FR 56245, September 18,

2000), we are evaluating lifting the stay in light of our Draft   Do not cite, quote or distribute 28 recent findings on the 8 hour ozone standard itself to address a prior remand of the standard by the D. C. Circuit concerning the potential for beneficial effects of ozone related to its effect on ultraviolet radiation exposure( 65 FR 56245, September 18, 2000), we are now evaluating lifting the stay in light of our recent response to the Court remand. In the meantime, on June 2, 2003 we published a proposed rulemaking for implementation of the 8 hour ozone NAAQS ( 68 FR 32801).

II. WHAT IS THE SCOPE OF THIS ACTION?

In this action, we are finalizing specific changes in response to the Court's rulings on the NOx SIP Call, Section 126, and Technical Amendments rulemakings. Specifically, we are finalizing the following:

( 1) Certain aspects of the definitions of EGU and non EGU.

We are addressing the definition of EGU as applied to cogeneration units by finalizing an EGU definition that excludes certain small cogeneration units for purposes of the NOx SIP Call and Section 126 rulemakings. We are also finalizing a non EGU definition that includes such cogeneration units. [ Note that a cogeneration unit may be owned by a utility or a non utility and is a unit that uses energy sequentially to produce both useful thermal energy ( heat or steam) used for Draft   Do not cite, quote or distribute 29 industrial, commercial, or heating or cooling purposes;

and electricity.]

( 2) The control level assumed for large stationary IC engines in the NOx SIP Call. We proposed a range of possible control levels ( 82 percent to 91 percent) to the IC engine portion of the budget. We are setting the control limit for large natural gas fired stationary IC engines in the NOx SIP Call at 82 percent, and for diesel and dual fuel stationary IC engines at 90 percent.

( 3) Partial State budgets for Georgia, Missouri, Alabama,

and Michigan in the NOx SIP Call.

( 4) Changes to the statewide NOx budgets in the NOx SIP Call to reflect the appropriate increments of emissions reductions that States should be required to achieve with respect to the three remanded issues ( discussed above in numbers 1, 2, 3).

( 5) The SIP submittal dates for the required States to address the Phase II portion of the budget, and for Georgia and Missouri to submit full SIPs meeting the NOx SIP Call. We proposed a range of dates 6 months through 1 year from promulgation of this rule, but no later than April 1, 2003. Based on comments and the delay in finalizing this rule, we are setting a SIP Draft   Do not cite, quote or distribute 30 submittal date 1 year from signature of this rule.

( 6) The compliance date for all covered sources to meet Phase II of the NOx SIP Call. We proposed a compliance date of May 31, 2004 ( or, if later, the date on which the source commences operation) for all sources except those in Georgia and Missouri. We proposed May 1, 2005 for sources in those States. We are setting the compliance date as May 1, 2007 ( or, if later, the date on which the source commences operation) for sources States choose to control under Phase II, including IC engines and sources in Georgia and Missouri. 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.

( 7) The exclusion of Wisconsin from the NOx SIP Call.

A. How Do We Treat Cogeneration Units and Non Acid Rain Units?

By way of background, in light of the Michigan decision concerning the NOx SIP Call, we adopted the view that the States should proceed with developing and submitting SIPs ( termed " Phase I" SIPs) reflecting the level of required Draft   Do not cite, quote or distribute 31 reductions that was not affected by the Court's ruling.

Accordingly, we determined that the Phase I SIPs, under the Court's ruling, by October 30, 2000, should reflect all reductions required under the NOx SIP Call, except those reductions attributable to parts of the rule that the Court remanded or vacated, such as reductions by small cogeneration units.

At the time, we were uncertain as to which specific units were small cogeneration units and what total emissions were attributable to small cogeneration units. Even so, we were aware that, although most of the EGUs that were subject to the NOx SIP Call were also subject to the Acid Rain Program, none of the small cogeneration units were subject to the Acid Rain Program. Accordingly, we erred on the side of caution by authorizing States, in their Phase I SIPs, to exclude the required reductions from all non Acid Rain units.

In the February 22, 2002 proposal, as applied to small cogeneration units, we proposed to retain the EGU definition in the Section 126 Rule and to retain the basic EGU definition used in the NOx SIP Call Rule with minor,

technical revisions to make it consistent with the definition in the Section 126 Rule. In today's action, we are finalizing an EGU definition that excludes certain small Draft   Do not cite, quote or distribute 7 This is based on both a review of the applicability provisions in the NOx SIP Call SIPs and the budget demonstrations for those SIPs. For more detailed discussion, see section K. 1 of today's preamble.

32 cogeneration units. All other cogeneration units and other non Acid Rain units are EGUs if the other criteria in the EGU definition are met. Further, we are finalizing a non

EGU definition that includes certain small cogeneration units. As a result, we are setting Phase II budgets that include reductions from small cogeneration units and non

Acid Rain EGUs.

However, our review of the SIPs submitted in response to the NOx SIP Call indicates that the States already included the non Acid Rain units in their Phase I SIPs as EGUs or non EGUs. 7 In addition, for today's final rule,

with the possible exception of one source, we have not identified any specific small cogeneration units that were originally treated by EPA, and by States in their Phase I SIPs, as EGUs and which now are defined as non EGUs because,

in general, commenters did not provide specific information identifying any such units. The only exception involves one commenter that claimed that its units ( located at the Tobaccoville facility) classified as EGUs should be classified as non EGUs. However, the commenter did not provide sufficient information ( e. g., information supporting Draft   Do not cite, quote or distribute 33 the maximum design heat input asserted by the commenter) for us to make a final determination regarding the proper classification of the units. Therefore, today's change does not result in any change to the originally finalized SIP Call budgets ( which included reductions from both Phase I and Phase II units).

Nevertheless, it is still possible that some cogeneration units that we classified as EGUs are small cogeneration units that should actually be treated as non

EGUs. To the extent any such units are subsequently identified to EPA, we will make any further revisions to the budgets of particular States during the SIP approval process. Similarly, we will consider, during the SIP approval process, the proper classification of the four units at the Tobaccoville facility identified by the commenter discussed above. Because we anticipate that few,

if any, existing units treated as EGUs qualify as small cogeneration units, we expect few, if any, such revisions to the budgets will be necessary and that any such revisions that are necessary will be relatively small and will not affect most States.

We are also finalizing certain technical changes to the EGU definition in the NOx SIP Call to make it consistent with aspects of the definition of EGU used in the Section Draft   Do not cite, quote or distribute 34 126 Rule. In addition, 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. In the process of correcting the EGU and non EGU definitions,

we are also finalizing some minor changes to the terminology, and minor corrections of awkward or inconsistent wording and grammatical errors in the applicability provisions.

To begin, we provide a discussion of what preceded today's final decision on the treatment of cogeneration units. Under the NOx SIP Call, the amount of a State's significant contribution to nonattainment in another State included the amount of highly cost effective reductions that could be achieved for large EGUs ( i. e., EGUs serving generators with nameplate capacity exceeding 25 MWe) and large non EGUs ( non EGUs with maximum design heat input capacity exceeding 250 mmBtu/ hr) in the State. No reductions for small EGUs or small non EGUs were included.

We determined that reductions by large EGUs to 0.15 lb NOx/ mmBtu and by large non EGUs to 60 percent of uncontrolled emissions are highly cost effective. In developing the States' budgets, we applied definitions of EGU and non EGU and determined which sources were large EGUs Draft   Do not cite, quote or distribute 35 or large non EGUs.

In its Michigan decision, the D. C. Circuit upheld this approach, but determined that we did not provide sufficient notice and opportunity to comment for one aspect of our definition of EGU and remanded the rule to us for further consideration. Specifically, a petitioner claimed, and the Court agreed, that " EPA did not provide sufficient notice and opportunity for comment on [ the] revision" of the EGU definition to remove the exclusion, from the EGU category,

of cogeneration units that supply one third or less of their potential electrical output capacity, or 25 megawatts ( MWe)

or less, to any utility power distribution system for sale.

Michigan v. EPA, 213 F. 3d at 691 92. ( These thresholds are herein referred to as the " one third potential electrical output capacity/ 25 MWe criteria;" cogeneration units that meet such criteria are herein referred to as " small cogeneration units.") According to the Court, " two months after the promulgation of the [ NOx SIP Call] rule, EPA redefined an EGU as a unit that serves a ` large' generator ( greater than 25 MWe) that sells electricity." Id.

Application of the exclusion for cogeneration units from the definition of EGU would result in treating as non EGUs those cogeneration units meeting the " one third potential electrical output capacity/ 25 MWe" criteria and treating as Draft   Do not cite, quote or distribute 36 EGUs those cogeneration units not meeting these criteria.

See Brief of Petitioner Council of Industrial Boiler Owners ( CIBO) at 4 ( submitted in Michigan).

The petitioner argued that, under the NOx SIP Call, we should apply these criteria for excluding cogeneration units from treatment as EGUs. According to the petitioner, the criteria had been established under the regulations implementing new source performance standards ( NSPS) and under title IV of the CAA and the regulations implementing the Acid Rain Program under title IV. The petitioner also stated that section 112 of the CAA defines " electricity steam generating unit" to exclude cogeneration units meeting the same thresholds.

The Court found that, in failing to apply the "

onethird potential electrical output capacity/ 25 MWe" criteria for cogeneration units, EPA " was departing from the definition of EGUs as used in prior regulatory contexts" and " was not explicit about the departure from the prior practice until two months after the rule was promulgated."

Michigan, 213 F. 3d at 692. Further, the Court found that:

it is an exaggeration to state that some general " theme" of the regulatory consequences of deregulation of the utility industry throughout rulemaking meant that EPA's last minute revision of the definition of EGU should have been anticipated by industrial boilers as a " logical outgrowth" of EPA's earlier statements. Draft   Do not cite, quote or distribute 37 Id. The Court therefore remanded the rulemaking to us for further consideration of this issue.

In its decisions on the Section 126 Rule and the Technical Amendments Rulemakings, the D. C. Circuit, after considering the merits of the issue, vacated and remanded our classification of small cogeneration units as EGUs.

Appalachian Power Section 126 and Appalachian Power

Technical Amendments. The Court held that we had failed to justify this classification and to base it on adequate record support comparing the NOx reduction costs of cogeneration units to those of other EGUs or demonstrating that there is no relevant physical or technological difference between small cogeneration units and other units treated as EGUs. The Court also remanded our classification of any cogeneration units as EGUs.

In response to the Court's decisions, we addressed the cogeneration unit issue in the February 22, 2002 proposed rule. In the proposed rule, we noted that, in prior regulatory programs, we sought to distinguish between utilities ( regulated monopolies in the business of producing and selling electricity) and non utilities ( e. g.,

independent power producers and industrial companies). In order to make this distinction, we applied the " one third potential electrical output capacity/ 25 MWe sales" criteria. Draft   Do not cite, quote or distribute 38 These criteria were not always applied only to cogeneration units and did not uniformly result in less stringent regulation for units meeting the criteria. In the proposed rule, we stated that, with the development of competitive markets for electricity generation and sale, we believed that these criteria no longer distinguish between units in the business of producing and selling electricity ( i. e.,

EGUs) and non EGUs. In addition, we explained that there are no relevant differences between the way cogeneratingcogeneration units and non

cogeneratingnoncogeneration units are built and operated that justify continuing to use these criteria or that affect the general ability of cogeneratingcogeneration units to control NOx.

In response to the February 22, 2002 proposed rule,

most commenters again argued that, under the NOx SIP Call,

we should apply the " one third potential electrical output capacity/ 25 MWe sales" criteria to exclude cogeneration units from treatment as EGUs. The comments included arguments that: classification of small cogeneration units reverses EPA precedent, contradicts Congressional intent,

and will discourage new industrial cogeneration; and it is technically and economically more difficult to control NOx emissions from non utility units. A few commenters supported treatment of small cogeneration units as EGUs. Draft   Do not cite, quote or distribute 39 Under today's final rulemaking, we are finalizing an EGU definition that excludes certain small cogeneration units and a corresponding non EGU definition that includes these units. We still maintain that, with the development of competitive markets for electricity generation and sale,

the " one third potential electrical output capacity/ 25 MWe sales" criteria no longer distinguishes between units in the business of producing and selling electricity ( i. e., EGUs)

and non EGUs. We also continue to believe that there are no relevant differences between the way cogeneratingcogeneration units and non

cogeneratingnoncogeneration units are built and operated that justify continuing to use these criteria or that affect the general ability of cogeneratingcogeneration units to control NOx.

However, at this time, we do not believe we have adequate record information comparing the NOx reduction costs of all types of industrial cogeneration units to those of other units that are treated as EGUs.

Our discussion below begins with some background on the historical definition of utility unit and the definition of EGU in the NOx SIP Call and the Section 126 rulemaking. We then discuss today's final rule, including our final decision on the treatment of cogeneration units and the specific revisions to the definition of EGU and Draft   Do not cite, quote or distribute 40 corresponding revisions to the definition of non EGU.

1. What is the Historical Definition of Utility Unit?

As discussed in the February 22, 2002 proposed rule ( 67 FR 8402 3), in prior regulatory programs, we have used variations of the " one third potential electrical output capacity/ 25 MWe sales" criteria to distinguish between utilities and non utilities. The Agency began using these criteria in 1978, in 40 CFR part 60, subpart Da. Subpart Da established NSPS for " electric utility steam generating units" capable of combusting more than 250 mmBtu/ hr of fossil fuel. " Electric utility steam generating unit" was defined as a unit " constructed for the purpose of supplying more than one third of its potential electric output capacity and more than 25 MWe electrical output to any utility power distribution system for sale" ( 40 CFR 60.41a).

In that case, the criteria were not used to exempt units entirely from NSPS. Rather, the criteria were used to classify units capable of combusting more than 250 mmBtu/ hr of fossil fuel as either " electric utility steam generating units" subject to the requirements under subpart Da or to classify them as non utility " steam generating units" that,

depending on the date of construction, continued to be subject to the requirements for " Fossil Fuel Fired Steam Generators" under subpart D or subsequently became subject Draft   Do not cite, quote or distribute 41 to the requirements for " Industrial Commercial Institutional Steam Generating Units" under subpart Db. See 40 CFR 60.41a ( definitions of " steam generating unit" and " electric utility steam generating unit"), § 60 § 60.40b( a) ( stating that subpart Db applies to " steam generating units" with heat input capacity of more than 100 mmBtu/ hr), and § 60 § 60.40b( e) ( stating that " electric steam generating units"

subject to subpart Da are not subject to subpart Db).

Depending on the specific circumstances ( e. g., type of equipment and fuel) of the unit involved, some of the emission limits in subpart Db may be the same as or more stringent than those in subpart D or Da.

We explained that we were distinguishing, in subpart Da, between " electric utility steam generating units" and " industrial boilers" because " there are significant differences between the economic structure of utilities and the industrial sector" ( 44 FR 33580, 33589, June 11, 1979).

The " one third potential electrical output capacity/ 25 MWe sales" criteria were used as a proxy for utility vs.

industrial/ commercial/ institutional ( i. e., non utility)

ownership of the units; utility owned units were covered by subpart Da, while non utility owned units were covered by subpart D or Db.

A similar type of distinction between utility and non Draft   Do not cite, quote or distribute 42 utility units ( using the " one third potential electrical output capacity/ 25 MWe sales" criteria) continued under the CAA Amendments of 1990, in both title IV and section 112 of title I, but was applied only to cogeneration units. Title IV established the Acid Rain Program whose requirements apply to " utility units." Section 402( 17)( C) excludes a cogeneration unit from the definition of " utility unit"

unless the unit " is constructed for the purpose of supplying, or commences construction after the date of enactment of [ title IV] and supplies, more than one third of its potential electric output capacity and more than 25 MWe electrical output to any utility power distribution system for sale." 42 U. S. C. 7651a( 17)( C). See also 40 CFR 72.6( b)( 4). Section 112 of the CAA, which addresses hazardous air pollutants, excludes from the definition of " electric utility steam generating unit" cogeneration units ( but not non cogeneration units) that meet the " one third potential electrical output capacity/ 25 MWe sales" criteria [ 42 U. S. C. 7412( a)( 8)]. Under section 112, emission limits established by the Administrator for the pollutants listed in section 112( b) apply generally to stationary sources but apply to " electric utility steam generating units" only if the Administrator makes a specific finding. The Administrator must conduct a study of the " hazards to public Draft   Do not cite, quote or distribute 43 health reasonably anticipated to occur" from emissions from such units and determine if regulation of " electric utility steam generating units" is " appropriate and necessary." 42 U. S. C. 7412( n)( 1)( A). In summary, the above described provisions vary as to both: ( 1) the application of the "

onethird potential electrical output capacity/ 25 MWe sales"

criteria, which apply to all units in some provisions and only to cogeneration units in other provisions; and ( 2) the consequences of a unit meeting the criteria, which results in the unit being subject to more stringent regulation under some provisions and less stringent or later regulation under other provisions.

2. What Was the NOx SIP Call Definition of EGU?

In the NOx SIP Call rulemaking, we continued the general approach, described above, of distinguishing between units in the electric generation business ( here, EGUs) and units in the industrial sector ( here, non EGUs). However,

we adopted a different method of defining which units are in the electric generation business by changing the definition of EGU. We defined EGU by applying to all fossil fuel fired units the methodology described in detail below and did not apply to cogeneration units the " one third potential electrical output/ 25 MWe sales" criteria. Under the methodology applied to all units, after determining the date Draft   Do not cite, quote or distribute 8 For purposes of the January 18, 2000 Section 126 final rule, we defined " electricity for sale under firm contract to the electric grid" as where " the capacity involved is intended to be available at all times during the period 44 on which a unit commenced operation ( i. e., commenced combusting fuel), we determined whether the unit should be classified as an EGU or a non EGU by applying the appropriate criteria depending on the commencement of operation date. Then we classified the unit as a large or small EGU or a large or small non EGU.

Specifically, we noted in a December 24, 1998 supplemental action that the NOx SIP Call used the following methodology for classifying all units ( including cogeneration units) in the States subject to the NOx SIP Call as EGUs or non EGUs ( 63 FR 71220, 71223). We applied this methodology to cogeneration units and not the "

onethird potential electrical output capacity/ 25MWe sales"

criteria. See idId.

( a)( i) For units commencing operation before January 1, 1996, we classified as an EGU any unit serving a generator producing any electricity for sale under firm contract to the electric grid. In the December 24,

1998 supplemental action, we did not define the term " electricity for sale under firm contract to the electric grid." 8 Draft   Do not cite, quote or distribute covered by the guaranteed commitment to deliver, even under adverse conditions" ( 65 FR 2694 and 2731). In the February 22, 2002 proposed rule, we proposed to adopt the definition for the term provided in the January 18, 2000 Section 126 final rule. This definition was based on language from the Glossary of Electric Utility Terms, Edison Electric Institute, Publication No. 70 40 ( definition of " firm" power). Generally, capacity " under firm contract to the electricity grid" is included on Energy Information Administration ( EIA) form 860A ( called EIA form 860 before 1998) or is reported as capacity projected for summer or winter peak periods on EIA form 411 ( Item 2.1 or 2.2, line 10).

45 ( ii) For units commencing operation before January 1,

1996, we classified as a non EGU any unit not serving a generator producing electricity for sale under firm contract to the grid.

( iii) For units commencing operation on or after January 1, 1996, we classified as an EGU any unit serving a generator producing any amount of electricity for sale, except as provided in paragraph ( a)( iv)

below.

( iv) For units commencing operation on or after January 1, 1996, we classified as non EGUs the following: any unit not serving a generator producing electricity for sale; or any unit serving a generator with a nameplate capacity equal to or less than 25 MWe,

producing electricity for sale, and with the potential to use 50 percent or less of the usable energy of the Draft   Do not cite, quote or distribute 9 For purposes of the January 18, 2000 Section 126 final rule, we used the more familiar term " potential electrical output capacity," rather than the term " usable energy." We defined " potential electrical output" using the longstanding definition of the latter term as " 33 percent of a unit's maximum design heat input" ( 65 FR 2694 and 2731). In the February 22, 2002 proposed rule, we proposed to adopt the same term and definition used in the January 18, 2000 Section 126 final rule. " Potential electrical output capacity" is used, and defined in this way, in part 72 of the Acid Rain Program regulations ( 40 CFR 72.2 and 40 CFR part 72, appendix D) and in the new source performance standards ( 40 CFR 60.41a).

10 In the part 96 model rule in the NOx SIP Call ( 63 FR 57356, 57514 38, October 27, 1998), and subsequently for purposes of the January 18, 2000 Section 126 final rule ( 65 FR 2729 and 2731), we adopted the long standing definition of " nameplate capacity" as " the maximum electrical generating output ( in MWe) that a generator can sustain over a specified period of time when not restricted by seasonal or other deratings as measured in accordance with the United States Department of Energy standards." In the February 22, 2002 proposed rule, we proposed to adopt the same definition used in the January 18, 2000 Section 126 final rule. The term is defined in this way in part 72 of the Acid Rain 46 unit. In the December 24, 1998 supplemental action, we did not define the term " usable energy." 9 ( b)( i) For a unit classified as an EGU under paragraph ( a)( i) or ( a)( iii) above, we then classified it as a small or large EGU. An EGU serving a generator with a nameplate capacity greater than 25 MWe is a large EGU.

An EGU serving a generator with a nameplate capacity equal to or less than 25 MWe is a small EGU. In the December 24, 1998 supplemental action, we did not expressly define the term " nameplate capacity." 10 Draft   Do not cite, quote or distribute Program regulations ( 40 CFR 72.2).

11 In the part 96 model rule in the NOx SIP Call ( 63 FR 57516) and subsequently for purposes of the January 18, 2000 Section 126 final rule ( 65 FR 2729), we defined " maximum design heat input" as " the ability of a unit to combust a stated maximum amount of fuel per hour ( in mmBtu/ hr) on a steady state basis, as determined by the physical design and physical characteristics of the unit." In the February 22, 2002 proposed rule, we proposed to adopt the same definition used in the January 18, 2000 Section 126 final rule.

12 For example, in establishing the State budgets for large EGUs and large non EGUs, we identified existing units as 47 ( ii) For a unit classified as a non EGU under paragraph ( a)( ii) or ( a)( iv) above, we then classified it as a small or large non EGU. A non EGU with a maximum design heat input greater than 250 mmBtu/ hour is a large non EGU. A non EGU with a maximum design heat input equal to or less than 250 mmBtu/ hour is a small non EGU. But see 63 FR 71224 ( explaining procedures used if data on boiler heat input capacity were not available). In the December 24, 1998 supplemental action, we did not expressly define the term " maximum design heat input." 11 The term is analogous to the term " nameplate capacity" in that it uses the manufacturer's specifications to categorize the size of the equipment ( the generator, in the case of an EGU or the boiler or turbine or combined cycle system, in the case of non EGU). 12 Draft   Do not cite, quote or distribute being large or small based on nameplate capacity ( for EGUs) or maximum design heat input ( for non EGUs), determined each unit's baseline heat input ( using 1995 or 1996) and, after calculating total heat input for large EGUs and for large non EGUs, grew the total amounts out to 2007 using heat input growth rates to account for new units and increased utilization. There was no provision for modifying the budgets to remove a unit initially qualifying as a large EGU or large non EGU if the unit changed its generating or heat input capacity.

48 As stated previously, we defined the term " EGU" by applying to all units, including cogeneration units, the methodology in paragraphs ( a)( i) and ( a)( iii) above and used the methodology in paragraphs ( a)( ii) and ( a)( iv) above to define units as non EGUs. We did not use, for cogeneration units, the " one third potential electrical output capacity/ 25 MWe sales" criteria in the cogeneration exclusion. It was the fact that we did not apply these criteria to cogeneration units that petitioners challenged in Michigan. As discussed further below, we are adopting essentially these criteria in today's final rule.

3. What is the Rationale for the Final Rule's Treatment of Cogeneration Units?

a. Distinction between units in the electric generation business and units in the industrial sector.

Distinguishing between units producing electricity for sale and units producing electricity for internal use or producing steam is a long standing approach in setting Draft   Do not cite, quote or distribute 49 emission limits. In the NOx SIP Call, the Section 126 Rule,

and today's final rule, we continue to take this general approach by setting different emission limits for units producing electricity for sale ( EGUs) and units that do not produce electricity for sale ( non EGUs).

We are retaining this general approach for several reasons. First, this is a long standing approach, and few,

if any, commenters in the NOx SIP Call and Section 126 rulemakings supported abandoning the distinction between units in the electric generation business and units in the industrial sector. Second, after organizing the units into these two categories, we found that there was some difference in the average compliance costs of the two groups. See 65 FR 2677, January 18, 2000 ( estimating average large EGU control costs as $ 1,432 per ton in 1990 dollars in 1997 and average large non EGU costs as $ 1,589 per ton). Third, this approach tends to result in units that directly compete in the electric generation business having to meet the same emission limit, and that result seems reasonable.

In the May 15, 2001 decision in the Section 126 case,

the D. C. Circuit expressed concern that, under the Section 126 Rule, a cogenerator that produces electricity for sale may be treated as an EGU, a cogenerator that produces Draft   Do not cite, quote or distribute 13 In fact, use of the " one third potential electrical output capacity/ 25 MWe sales" criteria for cogeneration units distinguishes between EGU cogeneration units and non EGU cogeneration units based on the cogenerator's amount of electricity sales and raises the same issue. Under these criteria, two physically identical cogeneration units could have different emission limits simply because one produces and sells the requisite amount of electricity and the other produces more electricity for internal use and does not sell the requisite amount.

50 electricity for internal use only may be treated as a non

EGU, and thus two units that are " identical physically" may be subject to different emission reduction requirements.

Appalachian Power, 249 F. 3d at 1062. We note that this issue is not unique to cogeneration units and is inherent in any regulatory program that distinguishes between units in the electric generation business and units that are in the industrial sector and sets different emission limits for the two groups. 13 As previously discussed, we are continuing to use the general approach of distinguishing between units in the electric generation business and units in the industrial sector in the NOx SIP Call and Section 126 Rule. We recognize that this may result in units that are physically identical being regulated differently based on whether or not electricity  particularly electricity for sale  is produced by the unit. However, before abandoning the longstanding approach of distinguishing between units on this basis  an action that few, if any, commenters in the NOx Draft   Do not cite, quote or distribute 51 SIP Call and Section 126 rulemakings have advocated  we believe that it is prudent to gain experience in operating the trading program under the NOx SIP Call and Section 126 Rule. We note that we have already begun the process of treating these units similarly because EGUs and non EGUs will participate in one trading program and will trade the same NOx allowances. After we have gained experience with the NOx SIP Call and Section 126 trading program, we intend to consider whether to treat as the same all large boilers,

whether they produce electricity or not.

b. Effect of electricity competition and electric power restructuring on distinction between utilities and non utilities. As discussed in the February 22, 2002 proposed rule ( see 67 FR 8405 06), the increasingly competitive nature of the electric power industry and the significant and increasing participation of non utilities ( e. g., an independent power producer or an industrial company) in competitive electricity markets support similar treatment of utilities and non utilities. In the proposed rule, we stated that, with these changes in the electric power industry and electricity markets, there is no longer a factual basis for excluding cogeneration units from treatment as EGUs by using the " one third potential electrical output capacity/ 25 MWe sales" criteria. Draft   Do not cite, quote or distribute 52 Many industry commenters argued that EGU should be defined to exclude a cogeneration unit meeting the "

onethird potential electrical output capacity/ 25capacity/ 25 MWe sales" criteria. They raised several issues in support of their argument of not including small cogeneration units in the definition of EGU. First, commenters argued that the classification of cogeneration units as EGUs reversed our precedent in previous regulations and contradicts Congressional intent underlying the CAA. They also argued that new industrial cogeneration, and the potential emissions and energy efficiency benefits that could result,

would be discouraged. In addition, commenters maintained that the costs of any NOx controls for these units would be reflected in the market for the products produced by the industrial company that uses energy from the cogeneration unit and not in the electricity market. Commenters maintained that a manufacturing company can engage in sales of electricity without being in the business of selling electricity. Sometimes such a company exports electricity to the local utility, even though it remains a net importer of electricity over the long term. Furthermore, commenters argued that we justified our definition on deregulation and have failed to consider the halt on deregulation efforts that California's electricity crisis spurred in other Draft   Do not cite, quote or distribute 53 States.

Although we have decided for the final rule to use the " one third potential electrical output capacity/ 25 MWe sales" criteria, we are not persuaded by most of the arguments commenters raised. For the reasons discussed in detail in the proposed rule ( 67 FR 8405 06), we continue to believe that the increasingly competitive nature of the electric power industry and the significant and increasing participation of non utilities in competitive electricity markets support similar treatment of utilities and nonutilities We also note that deregulation at the State level involves sales to end users, particularly residential and commercial customers, and a slow down ( or halt) in State level deregulation would not change this conclusion because the wholesale electricity market  where utilities and non utilities can compete for wholesale sales

continues to be deregulated at the Federal level.

Commenters claimed, but do not provide any documentation of the magnitude, that failure to apply the " one third potential electrical output capacity/ 25 MWe sales" criteria will discourage new industrial cogeneration. Further, while commenters argued that industrial companies with cogeneration units would be disadvantaged because the units'

NOx control costs would be reflected in the costs of the Draft   Do not cite, quote or distribute 54 products produced using energy from the units, they ignore the fact that industrial companies that instead buy electricity from utilities would presumably have utility units' NOx control costs reflected in electricity purchase costs.

c. Differences between the design and operation of cogeneratingcogeneration units and non

cogeneratingnoncogeneration units. In the February 22, 2002 proposed rule,

we stated that there appear to be no physical, operational,

or technological differences between cogeneration units producing electricity for sale and non cogeneration units producing electricity for sale that would prevent cogeneration units classified as EGUs from achieving average NOx reductions, and incurring average reduction costs,

similar to those achieved by non cogeneration units. We concluded in the proposed rule that there appear to be no such differences that would justify using the " one third potential electrical output capacity/ 25 MWe sales" criteria for classifying cogeneration units as EGUs or non EGUs,

rather than the classification methodology used for all other units. We still believe that there are no relevant differences between the way cogeneratingcogeneration units and non cogeneratingnon cogeneration units are built and operated that affect the general ability of Draft   Do not cite, quote or distribute 14 These two configurations are for cogeneration units in topping cycle cogeneration facilities, where energy is used sequentially, first to produce electricity and then to produce thermal energy for process use or heating and cooling. In bottoming cycle cogeneration facilities, energy is used sequentially first to produce thermal energy and then to produce electricity. ( See Cogeneration Applications Considerations, R. W. Fisk and R. L. VanHousen, GE Power Systems, 1996, Docket No. OAR 2001 0008, Item No. XII L 04 at 1 2.) The cogeneration units subject to the NOx SIP Call and the Section 126 Rule are boilers, turbines, or combined cycle systems and so are likely to operate in topping cycle cogeneration facilities.

55 cogeneratingcogeneration units to control NOx. However, at this time, we do not believe we have adequate record support comparing the NOx reduction costs of all types of industrial cogeneration units to those of other units that are treated as EGUs.

As discussed in the February 22, 2002 proposed rule,

cogeneration units under the NOx SIP Call or the Section 126 Rule operate in two basic configurations. 14 The first is a boiler followed by a steam turbine generator. In this configuration, steam is generated by a boiler. The steam is first used to power a steam turbine generator, while the remaining steam is used for an industrial application or for heating and cooling. The boiler that generates the steam used in this manner is designed and operated in essentially the same way as a boiler that generates steam used only to power a steam turbine generator. Therefore, any controls Draft   Do not cite, quote or distribute 56 that could be used on a boiler used to produce only electricity could also be used on a boiler used for cogeneration. In each case, the boiler emits the same amount of NOx.

The second typical configuration for a cogeneration unit is a gas fired combined cycle system. Combined cycle system plant refers to a system composed of a gas turbine,

heat recovery steam generator, and a steam turbine.

Combined cycle units that cogenerate isare designed and operated in essentially the same way as combined cycle units that generate only electricity. The waste heat from the gas turbine serves as the heat input ( possibly supplemented by a duct burner) to the heat recovery steam generator that is used to power the steam turbine. Both the gas turbine and the steam turbine are connected to generators to produce electricity. The gas turbine generator and the heat recovery steam generator portions can be adapted to supply process steam as well as electricity. These units typically emit at NOx levels well below 0.15 lbs/ mmBtu even without the use of post combustion controls. Furthermore, selective catalytic reduction ( SCR) has been used extensively on combined cycle units that are used for cogeneration and those used for generation of electricity only and results in NOx emissions at levels well below 0.15 lb/ mmBtu. ( See GE Draft   Do not cite, quote or distribute 57 Combined Cycle Product Line and Performance, GE Power Systems, October 2000, Docket No. OAR 2001 0008, Item No.

XII L 04 at 10 11.)

Both cogeneration configurations identified above are used at utility and non utility facilities that produce electricity for sale. The steam generated at these facilities is divided between powering a steam turbine and serving process uses or heating and cooling. The cogeneration units with the same configuration at these facilities are almost identical in design, except that a non utility facility may use more of the steam for process uses or heating and cooling and less for electricity generation.

Further, in comparison to a non cogeneration system that generates electricity for sale, either type of cogeneration system looks essentially the same as such a non cogeneration system except for the addition of valves and piping to send the steam for process use or heating and cooling. In both the cogeneration and non cogeneration systems that generate electricity for sale, all the flue gas ( containing the NOx emissions) exiting the combustion process can be directed through the pollution control devices and then through a stack. Because the cogeneration and non cogeneration systems are of essentially the same Draft   Do not cite, quote or distribute 15 For examples and discussion of how post combustion controls apply to cogeneration units, see Docket No. OAR 2001 0008 ( Legacy Docket No. A 96 56), Item Nos. XII L 02; XII L 03; and XII L 05 at 10 11 and 13 ( Figure 15). In fact, this is also true for boilers that do not serve any generator. Boilers with or without a generator and with or without the capability to cogenerate are of essentially the same design, and the flue gas exits the systems in the same manner. Any post combustion pollution control device used for NOx control in either system is located in the same place and operated in the same manner.

16 " Lack of Relevant Physical or Technological Differences Between Cogeneration Units and Utility Electricity Generating Units," September 25, 2000, Docket No. OAR 2001 0008 ( Legacy Docket No. A 96 56), Item No. XII K 47.

58 design and the flue gas exits the systems in the same manner, the control of NOx emissions can be achieved in the same manner. Any post combustion pollution control device used for NOx control in either system is located in the same place and operated in the same manner. 15 As discussed in the February 22, 2002 proposed rule and the technical support document, 16, post combustion NOx control technologies, i. e., selective non catalytic reduction ( SNCR)

and SCR, are available for use on both non cogeneration and cogeneration units producing electricity for sale. The technical support document and the other documents cited in the proposed rule support the following conclusions:

( 8) Selective non catalytic reduction is a fully commercial technology that uses reagent injected into the boiler above the combustion zone to reduce NOx to elemental Draft   Do not cite, quote or distribute 59 nitrogen and water. Because the NOx reduction takes place above the combustion zone, boiler type has an insignificant impact on the ability to use SNCR.

Selective non catalytic reduction has been demonstrated on a wide range of boiler types and sizes ( including cogeneration units) and on a wide range of fuels ( including bio mass, wood, or combinations of fuels such as bark, paper sludge, and fiber waste).

Selective non catalytic reduction has been used at a wide range of temperatures ( e. g., from 1250 degrees F to 2600 degrees F) and has been designed to handle a wide range of load variation ( e. g., 33 percent to 100 percent of a unit's maximum continuous rating).

( 9) Selective catalytic reduction is a fully commercial technology that uses both ammonia injected after the flue gases exit the boiler or the combustion turbine and catalyst in a reactor to reduce NOx to elemental nitrogen and water. Because the NOx reduction takes place in a reactor outside the combustion and heat transfer zones, boiler type has an insignificant impact on the ability to use SCR. The SCR has been demonstrated on a wide range of boiler types and sizes and on combined cycle systems. The SCR has been used at a wide range of temperatures ( e. g., 450 degrees F to Draft   Do not cite, quote or distribute 60 1100 degrees F) and has been designed to handle a wide range of load variation.

In the February 22, 2002 proposed rulemaking, we requested comment on, and specific information supporting or contradicting, our conclusions that there are no relevant physical, operational, or technological differences and no significant difference in average control retrofit cost for cogeneration versus non cogeneration units producing electricity for sale. In response to the proposed rule,

commenters raised concerns that it is technically and economically more difficult to control NOx in industrial cogeneration units than in non utility units because they are smaller sized than utility boilers, fire multiple fuels and often co fire two or more fuels, operate in a loadfollowing mode, have lower annual operating load or capacity factor, and have boiler temperature profiles and other factors that affect pollution control devices. A few commenters supplied data or indicated the cost of control for certain units. One commenter stated that reasonably available control technology ( RACT) analysis for an unidentified, 350 mmBtu/ hrmillion British thermal units( mmBtus)/ hr coal fired stoker boiler indicated that the only technically feasible NOx control identified by boiler and NOx control experts was conversion to fluidized bed Draft   Do not cite, quote or distribute 61 combustion at a cost of over $ 11,000/ ton based on year round operation and over $ 26,000/ ton considering only the ozone season. Another commenter cited EPA's " Alternative Control Techniques Document: NOx Emissions from Industrial/ Commercial/ Institutional Boilers" ( March 1994)( 1994 ACT), indicating cost effectiveness of SCR for a 400 mmBtu/ hr pulverized coal boiler of $ 3,400$ 4,200/ ton and cost effectiveness of SNCR for a 470 mmBtu pulverized coal boiler ( with low NOx burners and a 50 percent load factor)

of more than $ 1,800/ ton. An additional commenter indicated costs in excess of $ 2,500 per seasonal ton at the Tobaccoville facility ( in 1990 dollars).

In light of the limited control cost data provided by commenters, we conclude that at this time we lack sufficient cost data to show whether there is a significant difference in the average cost of controlling NOx emissions from cogeneration units, as compared to non cogeneration units.

The 1994 ACT costs cited by one commenter are not relevant because the boilers involved were not cogeneration units.

In addition, the cited costs were early estimates by the Agency on the cost of SCR and SNCR and have been superceded by later data and documents. Further, the commenters'

indicated that costs at the coal fired stoker and at the Tobaccoville facility do not necessarily support the claim Draft   Do not cite, quote or distribute 62 that average costs of controlling NOx at cogeneration units are higher than such costs at non cogeneration units. Due to economies of scale, smaller units, like some industrial cogeneration units and smaller utility units, may have costs that are higher than the average costs. We acknowledge that the actual cost impacts will vary from unit to unit, with the costs being lower for some and higher for others. In our analysis, we presented average costs of control and understood that some units may have higher costs than the average. We note that units may participate in a trading program that allows for the buying of allowances for units that have more difficulty controlling NOx emissions.

Furthermore, we note that we have cost information on one other cogeneration unit. In our cost analysis of EGUs,

we used an average capital cost of $ 69.70 to $ 71.80 per kilowatt for SCR on a 200 MWe coal fired EGU. See " Analyzing Electric Power Generation Under the CAAA," U. S.

EPA, March 1998, Docket No. OAR 2001 0008, Item No. V C 03 at A5 7 ( Table A5 5). The record shows a capital cost of $ 58 per kilowatt for SCR on a new coal fired cogeneration unit. See " Status Report on NOx Control Technologies and Cost Effectiveness for Utility Boilers," Northeast States for Coordinated Air Use Management and Mid Atlantic Regional Air Management Association, June 1998, Docket No. OAR 2001 Draft   Do not cite, quote or distribute 17 We also note that the dollar per ton cost for this installation is $ 2,800 to $ 3,000 per ton of NOx removed. This is higher than the average cost for EGUs because the unit started at a low NOx rate ( 0.16 lb/ mmBtu) and controls down to 0.07 0.08 lb/ mmBtu, not because the unit is a cogenerator. If the unit only generated electricity and had the same starting NOx rate, the cost would be the same.

63 0008, Item No. VI B 05 at 151 53. We maintain that this cost is reasonably consistent with the average cost that we determined for all EGUs. 17 However, as commenters noted,

industrial cogeneration units cover a wide range of firing types and fire a wide range of fuels. Since the cogeneration unit used as part of the basis for the control costs for EGUs was a medium size, pulverized coal plant,

very similar to many coal fired utility boilers, it is not necessarily representative of other types of boilers used for industrial cogeneration units such as stoker boilers firing a combination of fuels. Since we have limited control cost data for such other types of industrial cogeneration units, we believe that we do not have a sufficient record at this time to show whether there is a significant difference in the average cost of controlling NOx emissions from these units.

4. What Revisions Are Being Made to the Definition of EGU in the NOx SIP Call and the Section 126 Rule?

In today's final rule, we are addressing three aspects Draft   Do not cite, quote or distribute 64 of the EGU definition. First, for purposes of the NOx SIP Call and the Section 126 Rule and in a change from the February 22, 2002 proposed rule ( see 67 FR 8401 8410), we are finalizing an EGU definition that applies to cogeneration units the " one third potential electrical output/ 25 MWe sales" criteria in classifying the units as EGUs or non EGUs. For all other units, we are continuing to apply the basic approach used in the NOx SIP Call Rule,

described in the December 24, 1998 supplemental action ( 63 FR 71233), and the approach in the Section 126 Rule for such classification. Second, we are finalizing some minor changes to the categorization ( based on dates of commencement of operation) of units under the NOx SIP Call definition of EGU ( set forth in section II. A. 2 above) for purposes of applying the firm contract criterion used to classify units as EGUs. While the NOx SIP Call categorizes units as those commencing operation before January 1, 1996 and those commencing operation on or after January 1, 1996,

today's final rule categorizes units as those commencing operation before January 1, 1997, those commencing operation in 1997 or 1998, and those commencing operation on or after January 1, 1999. These new categories based on commencement of unit operation are the same as the categories adopted in the January 18, 2000 Section 126 final rule, under which Draft   Do not cite, quote or distribute 65 units commencing operation before 1999 and generating electricity for sale, but not for sale under a firm contract to the grid ( i. e., not under a guaranteed commitment to provide the electricity), were classified as non EGUs and units commencing operation in 1999 or thereafter and generating any electricity for sale were generally classified as EGUs. Today's final rule uses this same approach to classify units as EGUs or non EGUs, except for the application to cogeneration units of the " one third potential electrical output/ 25 MWe sales" criteria. Third,

we are also finalizing some minor changes to the terminology, and minor corrections of awkward or inconsistent wording and grammatical errors in the applicability provisions. For example, we are adopting the term " potential electrical output capacity" and the definitions of the terms " electricity for sale under firm contract to the electric grid," " potential electrical output capacity," " nameplate capacity," and " maximum design heat input" used in the January 18, 2000 Section 126 Rule.

a. Application of the " one third potential electrical output/ 25MWe sales" criteria, in lieu of the firm contract criterion, to cogeneration units. As explained in the NOx SIP Call Rule, described in the December 24, 1998 supplemental action ( 63 FR 71233), and the Section 126 Rule, Draft   Do not cite, quote or distribute 66 we adopted the approach of using the firm contract criterion for units ( non cogeneration and cogeneration units) that commenced operation before 1999. We stated that the criterion provides a reasonable transitional means of making the EGU/ non EGU classification since, for units commencing operation in 1999 or thereafter, a unit that generates any electricity for sale is classified as an EGU. We explained that the firm contract criterion provides a reasonable way of identifying which cogeneration units have been significantly enough involved in the business of generating electricity for sale that their owners have provided guaranteed commitments to provide electricity from the units to one or more customers. We also stated that the historical information necessary to apply the firm contract criterion to cogeneration units ( and other units) is already available to us. Capacity involved in sales of electricity " under firm contract to the electricity grid" has been generally included on EIA form 860A ( called EIA form 860 before 1998) or reported to EIA as capacity projected for summer or winter peak periods on EIA form 411 ( Item 2.1 or 2.2, line 10). The historical information from these forms is publicly available.

Nevertheless, in today's final rule, we are adopting the " one third potential electrical output/ 25MWe sales" Draft   Do not cite, quote or distribute 67 criteria for classifying cogenerations units as EGUs or non

EGUs. The reasons for this approach are discussed below in II. A. 4. Regardless of when a cogeneration unit commenced or commences operation, a cogeneration unit supplying more than one third of its potential electrical output and more than 25 MWe to a utility power distribution system for sale during any year in the relevant period is classified as an EGU, and a cogeneration unit that does not meet these criteria is classified as a non EGU. As stated above,

criteria are used in order to determine whether a cogeneration unit is exempt from the Acid Rain Program under section 402( 17)( C) of the CAA, as implemented under § 72.4( b)( 4) of the Acid Rain regulations. See 40 CFR 72.4( b)( 4); and 58 FR 15634, 15636 38 ( 1993). Consequently,

in implementing the use of the " one third" potential electrical output/ 25 MWe sales" criteria for classifying cogeneration units in the NOx SIP Call and in the Section 126 Rule, today's final rule references § 72.4 ( b)( 4). Thus,

in general, a cogeneration unit that meets the criteria for an unaffected unit in the Acid Rain Program under § 72.4( b)( 4) for the relevant time period is defined as a non EGU, while a cogeneration unit that fails to meet the criteria for such exemption for the relevant time period is defined as an EGU. Moreover, for cogeneration units Draft   Do not cite, quote or distribute 18 While we wish to be as consistent as possible in the definitions used in the NOx SIP Call and the definitions used in the Section 126 Rule, there is an important difference in the reason for categorizing units in the two rulemakings. In the NOx SIP Call, the definitions are used to set the State budgets and therefore need to focus on 1995 and 1996, the base years used for developing budgets. State specific growth rates were used to take into account units commencing operation after the base years. The NOx SIP Call model rule ( in part 96) did not use these definitions in the applicability and allowance allocation provisions, and States adopted their own applicability and allowance allocation provisions in their SIPs. Thus, the portion of the definitions that affects the NOx SIP Call is the portion pertaining to units in operation before January 1, 1997. In the Section 126 Rule, the definitions are used for purposes of determining applicability and allocating allowances. Thus, in the Section 126 Rule, the definitions must address units commencing operation after 1996, as well as those operating in 1995 and 1996.

68 commencing operation before January 1, 1997, the relevant period is 1995 1996; for cogeneration units commencing operation during 1997 1998 the relevant period is 1997 1998;

and for units commencing operation on or after January 1,

1999, the relevant period is 1999 and thereafter. These same periods or categories are used in classifying noncogeneration units as EGUs or non EGUs. We are adopting the categories so that a consistent set of categories applies to all units ( either cogeneration or non cogeneration units),

which will simplify and facilitate the categorization of units by EPA, States, and others. 18 As discussed below, we are continuing to apply the firm contract criterion ( for units commencing operation before 1999) or the electricity Draft   Do not cite, quote or distribute 69 sales criterion ( for units commencing operation in or after 1999) for classifying non cogeneration units as EGUs or non

EGUs.

b. Application of the firm contract criterion to noncogeneration units. As noted above, in the NOx SIP Call Rule [ as described in the December 24, 1998 supplemental action ( 63 FR 71233)] and the Section 126 Rule, we adopted the approach of using the firm contract criterion for noncogeneration units ( as well as for cogeneration units) that commenced operation before 1999. In the February 22, 2002 proposed rule, we did not reconsider that general approach for non cogeneration units, but only for cogeneration units.

However, we did propose minor changes in the categorization of non cogeneration units based on their date of commencement of operation. We proposed to adopt commencement of operation before 1999 or on or after January 1, 1999 as the dividing line between units to which the firm contract criterion are applied and those to which the electricity sales criterion are applied. Further, for application of the firm contract criterion, we proposed to distinguish between units commencing operation before 1997 and those commencing operation in 1997 or 1998. Some commenters on the proposed rule argued for the keeping of the " firm contract" language for units commencing operation Draft   Do not cite, quote or distribute 70 in 1999 or later, especially if we would continue with our proposed definition of EGUs with regard to cogeneration units.

In today's final rule, we are finalizing, for noncogeneration units, the categorization of units under the NOx SIP Call as those units commencing operation before January 1, 1997, those commencing operation in 1997 or 1998,

and those commencing operation on or after January 1, 1999.

The firm contract criterion is not applied to noncogeneration units commencing operation on or after January 1, 1999. The classification of units commencing operation on or after January 1, 1999 will be based on whether the unit produces any electricity for sale. In general, any non cogeneration unit that produces electricity for sale will be an EGU, except that the non EGU classification will apply to a unit serving a generator that has a nameplate capacity equal to or less than 25 MWe, from which any electricity is sold, and that has the potential ( determined based on nameplate capacity) to use 50 percent or less of the potential electrical output capacity of the unit.

As discussed in the February 22, 2002 proposed rule,

for several reasons, we are establishing January 1, 1999 as the cutoff date for applying EGU and non EGU definitions based on electricity sales under firm contract to the grid Draft   Do not cite, quote or distribute 71 and the start date for applying EGU and non EGU definitions based on electricity sales. First, information is available to us on electricity sales on a calendar year basis only.

Consequently, the classification of units based on whether the generators that they serve are involved in firm contract electricity sales must be made on a calendar year basis, and any cutoff must start on January 1. Second, use of the January 1, 1999 cutoff date for the NOx SIP Call is consistent with the use of that same cutoff date in the Section 126 Rule. Third, the January 1, 1999 cutoff date will limit the ability of owners or operators of new units that might otherwise qualify as large non EGUs from obtaining small EGU classification for the units and thereby avoiding all emission reduction requirements. For example,

since the cutoff date and the relevant period for determining electricity sales are past, the owner of a large new unit that would otherwise not serve a generator will not be able to obtain small EGU classification simply by adding a very small generator ( e. g., 1 MWe) to the unit and selling a small amount of electricity under firm contract to the grid.

c. Application of Section 126 terms and definitions and correction of awkward or inconsistent wording and grammatical errors. We also are finalizing for use in the Draft   Do not cite, quote or distribute 72 NOx SIP Call the same term " potential electrical output capacity," and the same definitions of the terms " electricity for sale under firm contract to the electric grid," " potential electrical output capacity," " nameplate capacity," and " maximum design heat input," adopted in the January 18, 2000 Section 126 final rule and used in the EGU definition in the regulations ( i. e., part 97) implementing the Section 126 program. The basis for these terms and definitions is set forth above.

In addition, we are correcting some awkward or inconsistent wording and grammatical errors without making any substantive change in the EGU and non EGU definitions.

For example, instead of referring to units commencing operation " on or after January 1, 1997 and before January 1,

1999" as in the February 22, 2002 proposed rule, the final regulations refer to units commencing operation " in 1997 or 1998."

By further example, with regard to units classified as EGUs, the proposed rule refers to a unit commencing operation before January 1, 1997 or in 1997 or 1998 that " had" a nameplate capacity greater than 25 MWe and refers to a unit commencing operation on or after January 1, 1999 " with" the requisite nameplate capacity. With regard to units classified as non EGUs, the proposed rule refers to a Draft   Do not cite, quote or distribute 73 unit commencing operation before January 1, 1997 or in 1997 or 1998 that " has" a maximum design heat input greater than 250 mmBtu/ hr and refers to a unit commencing operation on or after January 1, 1999 " with" the requisite maximum design heat input. This inconsistent wording concerning nameplate capacity and maximum design heat input, where sometimes the past tense, sometimes the present tense, and sometimes no tense are used for units that had already commenced commercial operation in the past, is confusing. The final regulations consistently reference nameplate capacity and maximum design heat without using past or present tense.

The regulations refer to generators " with" the requisite nameplate capacity and units " with" the requisite maximum design heat input.

By further example, the proposed rule refers to EGUs that " commenced operation" before January 1, 1997 or in 1997 or 1998 serving a generator that " produced electricity for sale" and to EGUs that " commence operation" on or after January 1, 1999 that serve a generator that " produces electricity for sale." The proposed rule also refers to non EGUs that " commenced operation" before January 1, 1997 or in 1997 or 1998 that " did not serve" a generator " producing electricity for sale" and to non EGUs that " commence operation" on or after January 1, 1999 that " at no Draft   Do not cite, quote or distribute 74 time serves" or " at any time serves" a generator " producing electricity for sale." This inconsistent wording and use of past and present tenses is also confusing. For example,

some units in the category of 1999 or later commencement of operation have already commenced operation while others will commence operation in the future. Yet, the present tense is used in reference to all such units. The final regulations consistently reference commencement of operation and production of electricity without using past or present tense.

d. Final EGU and non EGU definitions. For the reasons discussed above, we are adopting the following definitions of EGU and non EGU for the NOx SIP Call and the proposed definitions discussed above ( in footnotes 9, 10, 11, and 12)

for the terms " electricity for sale under firm contract to the electric grid," " potential electrical output capacity,"

" nameplate capacity," and " maximum design heat input" used in the EGU and non EGU definitions. ( The EGU and non EGU definitions, and definitions for related terms, adopted today for the Section 126 Rule are set forth below in the revised rule language accompanying this preamble.)

( a) The following units are classified as EGUs:

( 1) For non cogeneration units

( A) For units commencing operation before Draft   Do not cite, quote or distribute 75 January 1, 1997, a unit serving during 1995 or 1996,1966 a generator producing electricity for sale under a firm contract to the electric grid.

( B) For units commencing operation in 1997 or 1998, a unit, serving, during 1997 or 1998 a generator producing electricity for sale under a firm contract to the electric grid.

( C) For units commencing operation on or after January 1, 1999, a unit serving, at any time, a generator producing electricity for sale.

( 2) For cogeneration units

( A) For units commencing operation before January 1, 1997, a unit that fails to qualify as an unaffected unit under 40 CFR 72.6( b)( 4)

for 1995 or 1996 under the Acid Rain Program.

( B) For units commencing operation in 1997 or 1998, a unit that fails to qualify as an unaffected unit under 40 CFR 72.6( b)( 4) for 1997 or 1998 under the Acid Rain Program.

( C) For units commencing operation on or after January 1, 1999, a unit that fails to qualify as an unaffected unit under 40 CFR Draft   Do not cite, quote or distribute 76 72.6( b)( 4) for any year under the Acid Rain Program.

( b) The following units are classified as non EGUs:

( 1) For non cogeneration units

( A) For units commencing operation before January 1, 1997, a unit not serving during 1995 or 1996 a generator producing electricity for sale under a firm contract to the electric grid.

( B) For units commencing operation in 1997 or 1998, a unit not serving during 1997 or 1998 a generator producing electricity for sale under a firm contract to the electric grid.

( C) For units commencing operation on or after January 1, 1999, a unit:

( i) At no time serving a generator producing electricity for sale; or ( ii) At any time serving a generator with a nameplate capacity of 25 MWe or less producing electricity for sale, if any such generator hasd with the potential to use not more than 50 percent of the potential electrical Draft   Do not cite, quote or distribute 77 output capacity of the unit.

( 2) For cogeneration units

( A) For units commencing operation before January 1, 1997, a unit that qualifies as an unaffected unit under 40 CFR 72.6( b)( 4) for 1995 and 1996 under the Acid Rain Program.

( B) For units commencing operation in 1997 or 1998, a unit that qualifies as an unaffected unit under 40 CFR 72.6( b)( 4) for 1997 and 1998 under the Acid Rain Program.

( C) For units commencing on or after January 1, 1999, a unit that qualifies as an unaffected unit under 40 CFR 72.6( b)( 4) for each year under the Acid Rain Program.

( c) Units classified as EGUs or non EGUs under paragraphs ( a) and ( b) are classified as large or small as follows:

( 1) A unit under paragraph ( a) serving a generator with a nameplate capacity greater than 25 MWe is a large EGU.

( 2) A unit under paragraph ( a) serving a generator with a nameplate capacity equal to or less than 25 MWe is a small EGU.

( 3) A unit under paragraph ( b) with a maximum Draft   Do not cite, quote or distribute 78 design heat input greater than 250 mmBtu/ hour is a large non EGU.

( 4) A unit under paragraph ( b) with a maximum design heat input equal to or less than 250 mmBtu/ hour is a small non EGU.

5. What is the Effect on Cogeneration Unit Classification of Applying " One Third Potential Electrical Output Capacity/ 25 MWe Sales" Criteria, Rather Than the Same Methodology as Used for Other Units?

The petitioner in Michigan who successfully challenged the lack of application of the " one third potential electrical output capacity/ 25 MWe sales" criteria to cogeneration units claimed that the failure to apply such criteria would result in " sweeping previously unaffected non EGUs into the EGU category." Brief of Petitioner CIBO at 4 ( submitted in Michigan). The petitioner further suggested that, without the application of these criteria,

" any sale of electricity will make a non EGU a more stringently regulated EGU." Reply Brief of Petitioner CIBO at 1 ( submitted in Michigan).

As discussed above, large EGUs and large non EGUs are included in the determination of the amount of a State's significant contribution to nonattainment in another State.

No reductions by small EGUs or small non EGUs are included Draft   Do not cite, quote or distribute 79 in that determination.

Neither the petitioner nor any party that commented in the NOx SIP Call or the Section 126 rulemakings identified any specific, existing cogeneration units that, without the application of the " one third potential electrical output capacity/ 25 MWe sales" criteria, would be classified as large EGUs but that, with the application of such criteria,

would be classified as either large or small non EGUs. In fact, one commenter supporting the " one third potential electrical output capacity/ 25 MWe" sales criteria stated that applying the criteria to the NOx SIP Call " would not alter the Agency's baseline emissions inventory, since cogeneration units were, for the most part, classified correctly as non EGUs in EPA's current data base." See Responses to the 2007 Baseline Sub Inventory Information and Significant Comments for the Final NOx SIP Call ( 63 FR 57356, October 27, 1998), May 1999 at 9. In our proposed rule in response to the Court's decision, we again asked commenters to identify any specific, existing cogeneration units that, without the application of the " one third potential electrical output capacity/ 25 MWe sales" criteria,

would be classified as large EGUs but that, with the application of such criteria, would be classified as either large or small non EGUs. One commenter stated that up to 16 Draft   Do not cite, quote or distribute 80 cogeneration units in the paper and pulp industry units would be affected by the change in EGU definition. However,

the commenter not only failed to provide the names of any specific units but also stated that it lacked sufficient information to determine whether any of the units were selling electricity under firm contract to the grid. In short, the commenter did not really know whether the 16 units would actually be treated as EGUs if the " one third potential electrical output capacity/ 25 MWe sales" criteria were not applied.

For today's final rule, in light of the lack of such specific information in the comments, we were unable to identify any small cogeneration units whose classification as EGUs or non EGUs will change in light of the changes in the EGU and non EGU definitions adopted in the final rule.

The only exception may be for units at the Tobaccoville facility, which are addressed above. However, for the reasons discussed above, we will consider reclassification of these units during the SIP revision approval process.

Further, it is conceivable that there are other small cogeneration units that need to be reclassified from EGUs to non EGUs and that, therefore, further adjustments to the budgets of particular States may be necessary. We will also make such further adjustments during the SIP approval Draft   Do not cite, quote or distribute 81 process when we receive the information necessary to support such reclassifications of small cogeneration units. Because we anticipate that few, if any, units currently treated in the budgets as EGUs qualify as small cogeneration units, we expect few, if any, revisions to the budgets resulting from today's final rule, and if any revisions do result, we anticipate that they will be very small and will not affect most States.

In order to facilitate the SIP approval process, we request participants in the process of developing SIP revisions in response to today's final rule to identify by name, location, and plant and point identification any cogeneration unit that they believe should be classified as a large or small non EGU under the methodology in today's final rule and that would have been classified differently as a large or small EGU under the methodology in the proposed rule. We also request identification by name,

location, and plant and point identification of any cogeneration unit that should be classified as a large or small EGU under today's final rule methodology and that would have been classified as a large or small non EGU under the proposed methodology. In addition, we request information supporting any claimed EGU, non EGU, large, or small classification of each identified unit. Draft   Do not cite, quote or distribute 82 Persons that identify units as cogeneration units or small cogeneration units ( under the " one third potential electrical output capacity/ 25 MWe sales" criteria) should submit the following information to confirm their identification:

( 1) A description of the facility to demonstrate that the facility meets the definition of a " cogeneration unit"

under 40 CFR 72.2.

( 2) Data describing the annual electricity sales from the unit for every year from the unit's commencement of operation through the present. To provide this information,

persons should submit the same form as they used to report the information to the EIA, or if they have not reported the information to EIA, provide the same information on annual electricity sales as was or would have been required to be reported to EIA.

( 3) Information stating and supporting the value of the unit's maximum design heat input.

B. What Are the Control Levels and Budget Calculations for Stationary Reciprocating Internal Combustion Engines ( IC Engines)?

In the February 22, 2002 action, we proposed that highly cost effective controls are available for stationary IC engines. We proposed to assign a 90 percent emissions Draft   Do not cite, quote or distribute 83 decrease on average for large natural gas fired rich burn,

diesel, and dual fuel IC engines. For large natural gasfired lean burn IC engines, we proposed to assign a percent reduction from within the range of 82 to 91 percent. Based on available data regarding demonstrated costs,

effectiveness, availability, and feasibility of low emission combustion ( LEC) technology, and consideration of comments received in response to the proposal, we stated that we would determine a percent reduction number to use in calculating this portion of the NOx SIP Call budget decrease.

Today, we are recalculating the budgets to reflect a control level of 82 percent for the natural gas fired leanburn IC engines. Because the vast majority of large natural gas fired IC engines are lean burn, we are applying the 82 percent reduction to all large natural gas fired IC engines for the purpose of setting this portion of the budget. For the other IC engine subcategories ( diesel and dual fuel) we are using 90 percent control, as proposed.

1. Determination of Highly Cost eEffective Reductions and Budgets.

As described in the NOx SIP Call final rule, after determining the degree to which NOx emissions, as a whole from the particular upwind States, contribute to downwind Draft   Do not cite, quote or distribute 84 nonattainment or maintenance problems, we determined whether any amounts of the NOx emissions may be eliminated through controls that, on a cost per ton basis, may be considered to be highly cost effective. By examining the cost effectiveness of NOx controls, we determined that an average of approximately $ 2,000 per ton removed is highly cost effective. We first projected the total amount of NOx emissions that sources in each covered State would emit,

accounting for their projected growth and measures required under the CAA, in 2007. We then projected the total amount of NOx emissions that each of those States would emit in 2007 if each State applied the highly cost effective measures ( the State's budget). The difference between the 2007 base inventory and the budget for each State is that State's " significant contribution" to downwind nonattainment. For a more detailed discussion of the determination of cost effective reductions and budgets, see the October 27, 1998 NOx SIP Call ( 63 FR 57399 57403 and 57405, respectively).

2. What Are the Key Comments We Received Regarding IC Engines?

The following describes key comments regarding IC engines and provides our responses. Additional comments and responses are contained in the Response to Comments ( RTC) Draft   Do not cite, quote or distribute 19 Note: Use of a higher uncontrolled value would result in a higher overall percentage control value. For example, assuming a control level of 3.0 g/ bhp hr the percentage control value would be 82 percent using 16.8 g/ bhp hr as the uncontrolled level and 75 percent using 12.0 as the uncontrolled level.

85 document associated with this rulemaking. Related information is also contained in the Technical Support Document ( TSD) ( revised version) associated with this rulemaking.

a. Level of NOx control.

( 1) NOx uncontrolled emission rate.

Comment: Several commenters suggested that we should rely on the July 2000 AP 42 emission factor documents ( Docket No.

OAR 2001 0008, Item Nos. XII D 09 and XII D 10) for the average uncontrolled emission rates [ 11.7 g/ bhp hr ( grams per brake horsepower hour) for 2 stroke engines and 15.1 g/ bhp hr for 4 stroke engines]. The commenters object to our use of a higher value ( 16.8 g/ bhp hr) as the uncontrolled level. 19 The commenters state that the July 2000 AP 42 factors are best because:

° they are based on actual engine emission tests;

° the engines tested are similar to " large" NOx SIP call engines;

° they are not based on horsepower categories;

° they tested both 2 and 4 stroke engines; and Draft   Do not cite, quote or distribute 20 See footnotes "( a)" to Tables 3.2 1 and 3.2 2 in the July 2000 AP 42 document.

86 ° they have documented quality control.

Response: We reviewed the data used to update AP 42. In order to focus on the large engines addressed in the NOx SIP Call, as suggested by commenters, we examined test data from those engines greater than 2,000 horsepower ( hp) operating at greater than 90 percent load. The large engines in this data base cover only 2 engine models and 8 tests; both models are 4 stroke engines. According to comments from the Interstate Natural Gas Association of America ( INGAA), about 85 percent of the large engines in the NOx SIP Call area are 2 stroke. Furthermore, as described in the July 2000 AP 42 document, the data presented do not differentiate between uncontrolled lean burn engines and engines that may be turbocharged. 20 Thus, the average " uncontrolled" emissions reported may include some engines with lower NOx emissions due to the turbocharging. We conclude that this data base is helpful but too limited to stand by itself considering the large amount of data available from other sources.

Instead, the AP 42 data must be reviewed along with other data as described below.

Comment: Commenters state that our 16.8 g/ bhp hr average is derived from " mostly" new engine models in 1991, not the Draft   Do not cite, quote or distribute 21 The letter addressed concerns regarding the OTC's development of a set of model NOx rules, including rules for stationary IC engines.

87 entire, current population of existing engines. According to commenters, the 1994 ACT document numbers are not representative of older NOx SIP Call type engines, the details of the data are unavailable, and the 16.8 value cannot be replicated. The commenters indicate that our weighted average approach does not correspond to engine models in the NOx SIP Call population, that the NOx 1994 ACT reflects 1991 manufacturer's letters for new, 4 stroke engines, and that we need to make these letters available.

Response: We have examined data from the pipeline industry,

data recently collected by the Agency, and data from the 1994 ACT document ( see RTC or TSD for details). These include data from large engines covered by the NOx SIP Call as suggested by some commenters. We believe the data support the 16.8 value proposed, as described below.

Emissions data compiled by three pipeline industry companies provide support to the 16.8 g/ bhp hr value proposed by us or a slightly higher value. Test data are contained in two letters to the Ozone Transport Commission ( OTC) in November 2000. Based on a survey of LEC retrofit installation in NOx SIP Call States, two pipeline companies in a November 20, 2000 letter to the OTC, 21 presented data Draft   Do not cite, quote or distribute 22 The weighted average was calculated as follows: ( 66 x 18.2 + 14 x 14.1 + 62 x 17.6) divide sum by 142 = 17.5.

88 on pre LEC and post LEC emissions for 86 engines in NOx SIP Call States. Most of the engines are relatively large, at 2000 hp or greater. Table 1 of the letter summarizes the data and states that the average uncontrolled NOx emissions level for these 86 engines is 16.8 g/ bhp hr, identical to the level we proposed. Considering only those engines greater than or equal to 2,000 hp, there are 66 engines with an average uncontrolled emissions rate of 18.2 g/ hp hr ( see RTC or TSD for details). Additional data in the same letter provide pre LEC and post LEC data for 20 engines. The letter states that the average uncontrolled NOx emissions for the 20 engines is 14.1 g/ bhp hr. Another major pipeline company also sent a letter ( November 22, 2000) to the OTC presenting uncontrolled and RACT emission rates for 62 engines retrofit with LEC ( see RTC or TSD for details). The average uncontrolled emission rate, considering all 62 engines from this data set, is 17.6 g/ bhp hr. The weighted average of these three data sets is 17.5 g/ bhp hr. 22 In response to comments, we collected additional test data to better determine controlled and uncontrolled emission levels from the current population of large engines in the NOx SIP Call area. Forty two data points were Draft   Do not cite, quote or distribute 23 For large lean burn IC engines in the NOx SIP Call States, 2 stroke engines represent 83 percent of the total large engines and 85 percent of the total large engine horsepower. ( From INGAA's April 22, 2002 comments, pages 2 and 10.) ( Docket No. OAR 2001 0008, Item No. XII D 09).

89 collected ( see RTC or TSD for details). The average uncontrolled NOx level from this data is 16.7 g/ bhp hr,

nearly identical to the proposed level of 16.8 g/ bhp hr.

As suggested by commenters, we also examined the available data separately for 2 and 4 stroke engines. The test data for the large IC engines in the NOx SIP Call area indicate uncontrolled levels of 16.4 and 18.9, respectively,

for the 2 and 4 stroke engines. Using information from the pipeline industry that about 85 percent of the engines in the NOx SIP Call area are 2 stroke, the weighted average of the 16.4 and 18.9 values is 16.8, identical to our proposed value. 23 As described in the 1994 ACT document for stationary IC engines, uncontrolled emission levels were provided to us by several engine manufacturers. Most manufacturers provided emission data only for current production engines, but some included older engine lines as well. The manufacturers'

letters were placed in the docket. These emission levels were tabulated and averaged for engines with similar power ratings. For engines greater than 2000 hp, the average Draft   Do not cite, quote or distribute 90 uncontrolled emission rate from 55 engines is approximately 16.8 g/ bhp hr. As noted in the TSD, there are several reasons to use the 1994 ACT document data. Using the applicable 1994 ACT document is consistent with how we treated other non EGU source categories in the NOx SIP Call rulemaking. The 1994 ACT document provides a comprehensive look at the IC engine class and has the advantage of using a consistent data set for uncontrolled emissions, costs, and controls. The 1994 ACT document uses a large data set from which to draw conclusions. The 1994 ACT document test data are available in several horsepower size categories which is important since we chose not to calculate emissions reductions from the smaller IC engines.

In summary, based on the 1994 ACT document data, the data contained in the industry letters to OTC and data we recently collected, there is considerable agreement with the 16.8 g/ bhp hr uncontrolled emission rate value that we proposed. The data do not support commenters suggestion for a lower value, namely 11.7 g/ bhp hr for 2 stroke engines and 15.1 g/ bhp hr for 4 stroke engines. Therefore, we conclude that use of the 16.8 g/ bhp hr level is appropriate to represent average, uncontrolled emissions.

( 2) NOx controlled emission rate with LEC technology. Draft   Do not cite, quote or distribute 91 Comment: Appendix B to INGAA's April 22, 2002 comment letter lists 226 lean burn large and small IC engines in the NOx SIP Call States that are retrofit with LEC technology and for which they could obtain State NOx permit limits.

The average post control NOx permit levels for 2 stroke and 4 stroke engines are reported to be 5.0 and 3.7,

respectively. The INGAA states that NOx permit limits are appropriate for use in calculating the average post control emission rate for lean burn engines in the NOx SIP Call area for the following reasons:

° these engines are located in the NOx SIP Call States, and represent the same makes and models as the large NOx SIP Call engines,

° these engines operate under State permit limits that reflect the emission control achieved by LEC on actual and identified individual engines,

° the emission control limits were established as the result of a formal regulatory process conducted by the State permitting agencies, and ° the LEC retrofits are consistent with the technology and costs identified by our NOx SIP Call TSDs.

Response: We disagree that permit limits are appropriate for determining the post control emission rate. Permit Draft   Do not cite, quote or distribute 24 See docket for e mail from John Patton dated May 30, 2002 and attachments. ( Docket No. OAR 2001 0008, Item No. 0917).

25 See Docket No. OAR 2001 0008 ( Legacy No. A 96 56), Item No. XII M 01 for November 20, 2000 letter, appendices A & B.

26 See Docket No. OAR 2001 0008, Item No. 0921 for June 5, 2002 fax from Randy Hamilton.

27 Ventura County Rule 74.9 ( in effect September 1989 to December 1993) applied to engines greater than or equal to 100 hp and required 125 ppm ( 1.7 g/ bhp hr) or 80 percent control. Current Ventura County Rule 74.9 requires 45 ppmv 92 limits generally do not reflect the actual emission rate and, thus, are not appropriate to determine the emission rates to be expected from installation of LEC technology.

For example, State records indicate permit limits of 18 and 8 even though LEC technology is in place and the target emission rate in the State RACT plan is 3 for both engines. 24 In another case, the permit level is 3.0, but the actual rate is reported as 1.7.25 The permit limits for six engines at a station in one State are 3.0 g/ bhp hr while the test data show emissions at less than 1.1 g/ bhp hr for each engine. 26 We agree with the comment that LEC retrofits are consistent with the costs identified by our NOx SIP Call TSDs.

Further, if we were to use permit rates, it makes no sense to ignore permit limits set in areas outside the NOx SIP Call region. California and Texas permits, for example,

have very low emission rates for IC engines. 27 The permit Draft   Do not cite, quote or distribute ( 0.6 g/ bhp hr) or 94 percent control. For best available retrofit control technology, California Air Resources Board selected for engines greater than or equal to 100 hp 65 ppm ( 0.9 g/ bhp hr) or 90 percent control, based on Sacramento Air Quality Management Division Rule 412. In Texas, requirements applicable in Houston are 0.5 0.6 g/ bhp hr for lean burn engines.

28 We proposed to select a value within the range of 82 to 91 percent control ( 1.5 3.0 g/ bhp hr controlled level assuming 16.8 uncontrolled level) based primarily on information in the 1994 ACT document.

29 This equates to a 5.0 g/ bhp hr limit, assuming an uncontrolled level of 16.8 g/ bhp hr.

93 levels suggested by commenters are limited because the permits generally reflect RACT requirements. However,

highly cost effective controls under the NOx SIP Call are not limited to RACT level stringency and should take into account improvements in control efficiency and cost effectiveness that have occurred over the last several years since the RACT generation of controls.

Comment: Commenters state that data we used to support the proposed controlled levels28 are for new or rebuilt engines

 not retrofits and therefore, cannot be relied upon. They suggest we should use NOx limits for engines retrofit with LEC in State permits and that the permits suggest no more than a 70 percent reduction. 29 Several commenters indicate it is important to examine the specific engines in the NOx SIP Call States to determine whether the reductions we assumed are achievable. Comments suggest that industry Draft   Do not cite, quote or distribute 30 For example, November 30, 1998 letter from INGAA to EPA ( Docket No. OAR 2001 0008, Item No. 0919), February 16, 1999 memo from INGAA to Tom Helms, EPA ( Docket No. OAR 2001 0008, Item No. XII K 38), and April 26, 2002 comment letter from Kinder Morgan ( Natural Gas Pipeline Company of America)( Docket No. OAR 2001 0008, Item No. XII D 24).

94 experience through RACT retrofits, has demonstrated that the stringent emission rates of 1.5 to 3.0 g/ bhp hr are not achievable on many engines and the average emission reduction to be expected for LEC retrofits is 70 percent.

Comments from the New Hampshire Department of Environmental Services expressed support for a 90 percent control level.