[Federal Register Volume 67, Number 36 (Friday, February 22, 2002)]
[Proposed Rules]
[Pages 8396-8425]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 02-3917]



[[Page 8395]]

-----------------------------------------------------------------------

Part IV





Environmental Protection Agency





-----------------------------------------------------------------------



40 CFR Parts 51, 52, et al.



Interstate Ozone Transport: Response to Court Decisions on the 
NOX SIP Call, NOX SIP Call Technical Amendments, 
and Section 126 Rules; Proposed Rule

  Federal Register / Vol. 67, No. 36 / Friday, February 22, 2002 / 
Proposed Rules  

[[Page 8396]]


-----------------------------------------------------------------------

ENVIRONMENTAL PROTECTION AGENCY

40 CFR Parts 51, 52, 96, and 97

[FRL-7147-6]
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: Proposed rule.

-----------------------------------------------------------------------

SUMMARY: In today's action, we are proposing to amend two related final 
rules we issued under sections 110 and 126 of the Clean Air Act (CAA) 
related to interstate transport of nitrogen oxides (NOX), 
one of the main precursors to ground-level ozone. 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 State Implementation Plan Call 
(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.
    In the final NOX SIP Call, we found that emissions of 
NOX from 22 States and the District of Columbia (23 States) 
significantly contribute to downwind areas' nonattainment of the 1-hour 
ozone national ambient air quality standards (NAAQS). We established 
statewide NOX emissions budgets for the affected States. In 
rulemakings providing technical amendments to the NOX SIP 
Call budgets, we revised those budgets. Today's action addresses the 
issues remanded by the Court in the two cases involving challenges to 
both the NOX SIP Call and the rulemakings providing 
technical amendments for notice-and-comment rulemaking and proposes 
related amendments.
    In today's action, we are also responding to the D.C. Circuit's 
decisions in a third case concerning a related rulemaking, the Section 
126 Rule, in which the Court remanded an issue and vacated an issue. 
This action addresses the vacated issue.

DATES: Comments must be postmarked, faxed, or e-mailed by April 15, 
2002. A public hearing, if requested, will be held in Washington, DC, 
on March 15, 2002, beginning at 9:00 am.

ADDRESSES: Comments (in duplicate if possible) may be submitted to the 
Office of Air and Radiation Docket and Information Center (6102), 
Attention: Docket No. A-96-56, U.S. Environmental Protection Agency,401 
M Street, SW, Washington, DC 20460, telephone (202) 260-7548, fax (202) 
260-4400, and e-mail [email protected]. We encourage electronic 
submissions of comments and data following the instructions under 
SUPPLEMENTARY INFORMATION of this document. No confidential business 
information (CBI) should be submitted through e-mail.
    The public hearing, if requested, will be held at Crystal Mall 2 
(Room 1110; the ``fishbowl''), Crystal City, 1921 Jefferson Davis Hwy, 
Arlington, VA 22202.
    Documents relevant to this action are available for inspection at 
the U.S. Environmental Protection Agency, 401 M Street, SW, Waterside 
Mall, Room M-1500, Washington, DC 20460, between 8 a.m. and 5:30 p.m., 
Monday through Friday, excluding legal holidays. A reasonable fee may 
be charged for copying.

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 at 
[email protected]. Technical questions concerning EGUs in today's 
document 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 
[email protected]; technical questions concerning internal 
combustion 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 [email protected]; 
legal questions should be directed to Howard J. Hoffman, Office of 
General Counsel, (2344A), 1200 Pennsylvania Ave., NW, Washington, DC 
20460, telephone (202) 564-5582, e-mail [email protected]. 

SUPPLEMENTARY INFORMATION: Today's action addresses the issues remanded 
or vacated for notice-and-comment rulemaking 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) and 
Appalachian Power v. EPA, No.99-1200, Order (D.C. Cir., August 24, 
2001), which concerned the section 126 rulemaking (the ``Section 126 
case'').
    In this action, we are proposing to:
    (1) Retain the definition of EGUs as it relates to cogeneration 
units in the NOX SIP Call and in the Section 126 Rule, and 
retain the definition of EGUs as it relates to cogeneration units in 
the NOX SIP Call with only minor revisions to make the 
definition consistent with the Section 126 Rule.
    (2) Revise the control levels for stationary internal combustion 
engines that were assumed in calculating NOX SIP call 
budgets for each State,
    (3) Exclude portions of Georgia, Missouri, Alabama and Michigan 
from the NOX SIP Call (the court ruling focused on Georgia 
and Missouri, but the same issue is relevant to Alabama and Michigan),
    (4) Revise statewide emissions budgets in the NOX SIP 
Call to reflect the disposition of the first three issues above,
    (5) Set a range of dates for 19 States and the District of Columbia 
to submit State implementation plans to achieve the emissions 
reductions required by this second phase of the NOX SIP 
Call, and for Georgia and Missouri to submit SIPs meeting the full 
NOX SIP Call: 6 months through 1 year from final 
promulgation of this rulemaking but no later than April 1, 2003,
    (6) Set a compliance date of May 31, 2004, for all sources except 
those in Georgia and Missouri; and sources in those two States would 
have a May 1, 2005 compliance date,
    (7) Exclude Wisconsin from NOX SIP Call requirements.
    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-

[[Page 8397]]

existing respiratory disease such as asthma), increased inflammation of 
the lungs, and possible long-term damage to the lungs.

Public Hearing

    A public hearing, if requested, will be held on March 15, 2002 
beginning at 9:00 am. The hearing will be held at Crystal Mall 2 (Room 
1110, the ``fishbowl''), Crystal City, 1921 Jefferson Davis Hwy, 
Arlington, VA 22202. The metro stop is Crystal City, which is located 
about 1 \1/2\ blocks from Crystal Mall 2. If you wish to request a 
hearing and present oral testimony or attend the hearing, you should 
notify, on or before March 7, 2002, Ms. JoAnn Allman, Office of Air 
Quality Planning and Standards, Air Quality Strategies and Standards 
Division, C539-02, Research Triangle Park, NC 27711, telephone (919) 
541-1815, e-mail [email protected]. Oral testimony will be limited 
to 5 minutes each. The hearing will be strictly limited to the subject 
matter of the proposal, the scope of which is discussed below. Any 
member of the public may file a written statement by the close of the 
comment period. Written statements (duplicate copies preferred) should 
be submitted to Docket No. A-96-56 and, to the extent they concern the 
Section 126 Rule, Docket No. A-97-43, at the address listed above for 
submitting comments. The hearing schedule, including lists of speakers, 
will be posted on EPA's webpage at http://www.epa.gov/ttn/rto/whatsnew.html. A verbatim transcript of the hearing and written 
statements will be made available for copying during normal working 
hours at the Office of Air and Radiation Docket and Information Center 
at the above address listed for inspection of documents.
    If no requests for a public hearing are received by close of 
business March 7, 2002, the hearing will be cancelled. The cancellation 
will be announced on the webpage at the address shown above.

Electronic Availability

    Electronic comments are encouraged and can be sent directly to EPA 
at: [email protected]. Electronic comments must be submitted as an 
ASCII file avoiding the use of special characters and any form of 
encryption. Comments and data will also be accepted on disks in 
WordPerfect in 8.0 file format or ASCII file format. All comments and 
data in electronic form must be identified by the docket number A-96-56 
and, to the extent they concern the Section 126 Rule, docket number A-
97-43. Electronic comments on this proposed rule may be filed online at 
many Federal Depository Libraries.

Availability of Related Information

    The official records for the NOX SIP Call rulemaking 
(including the Technical Amendments) and for the Section 126 Rule, as 
well as the public versions of the records, have been established under 
docket numbers A-96-56 and A-97-43, respectively (including comments 
and data submitted electronically as described below). We have added 
new sections to those dockets for purposes of today's proposed 
rulemaking. The public version of these records, including printed, 
paper versions of electronic comments, which does not include any 
information claimed as CBI, are available for inspection from 8:00 a.m. 
to 5:30 p.m., Monday through Friday, excluding legal holidays. The 
rulemaking records are located at the address in ADDRESSES at the 
beginning of this document. In addition, the Federal Register 
rulemakings and associated documents are located at http://www.epa.gov/ttn/rto/.

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-Hour 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 EPA's Request to Lift the Stay 
of the 1-Hour SIP Submission Schedule?
    6. What Was the Court's Order for the Compliance Date Order?
    C. What Was 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 EPA's Process for Addressing the Remands/Vacaturs?
    II. What is the Scope of this Proposal?
    A. How Do We Treat Cogenerators and Non-Acid Rain Units?
    1. What is the Historical Definition of Utility Unit?
    2. What is the NOX SIP Call Definition of EGU?
    3. What Minor Revisions Are Being Made to the Definition of EGU 
in the NOX SIP Call and the Section 126 Rule?
    4. What Methodology Are We Using to Classify EGU/non-EGU 
Cogeneration Units?
    5. What is the Effect on Cogeneration Unit Classification of 
Applying the Same Methodology As Used For Other Units, Rather Than 
the One-third Potential Electrical Output Capacity/25 MWe Sales 
Criteria?
    B. What Control Level is Being Proposed for Stationary 
Reciprocating Internal Combustion (IC) Engines?
    1. What Control Level Was Used in the NOX SIP Call?
    2. What Was the March 3, 2000 Court Decision Regarding IC 
Engines?
    3. What Are the Emissions from IC Engines?
    4. What Control Technologies Are Available For IC Engines?
    5. Is SCR An Appropriate Technology For Natural Gas-Fired Lean-
Burn IC Engines?
    6. Is LEC Technology Appropriate For Natural Gas-Fired Lean-Burn 
IC Engines?
    7. What NOX SIP Call Budget Calculations Are We 
Proposing?
    C. What is Our Response to the Court Decision on Georgia and 
Missouri?
    D. What Are We Proposing for Alabama and Michigan in Light of 
the Court Decision on Georgia and Missouri?
    E. What Modifications Will be 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?
    J. What SIP Submittal Dates Are We Proposing?
    K. What Compliance Dates Are We Proposing?
    1. What is the Technical Feasibility of the Compliance Dates?
    2. How Will This Affect Electric Reliability?
    L. What Are We Proposing for Wisconsin?
    M. How Are the 8-Hour NAAQS Rules Affected by This Action?
III. What Are the Administrative Requirements?
    A. Executive Order 12866: Regulatory Impact Analysis
    B. Executive Order 12898: Environmental Justice
    C. Executive Order 13045: Protection of Children from 
Environmental Health Risks and Safety Risks
    D. Executive Order 13132: Federalism
    E. Executive Order 13175: Consultation and Coordination with 
Indian Tribal Governments
    F. Executive Order 13211: Actions Concerning Regulations That 
Significantly Affect Energy Supply, Distribution, or Use
    G. Unfunded Mandates Reform Act
    H. Regulatory Flexibility Act (RFA), as Amended by the Small 
Business Regulatory Enforcement Fairness Act of 1996 (SBREFA)
    I. Paperwork Reduction Act
    J. National Technology Transfer and Advancement Act


[[Page 8398]]



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 23 States emit NOX in amounts that 
significantly contribute to nonattainment of the 1-hour ozone 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 
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 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 23 States emit NOX in amounts that significantly 
contribute to nonattainment of the 8-hour ozone NAAQS. However, we have 
indefinitely stayed the NOX SIP Call as it applies for the 
purposes of the 8-hour NAAQS (65 FR 56245, September 18, 2000).

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

1. What Was the Decision of the Court on the 8-Hour NAAQS?
    On May 14, 1999, the D.C. Circuit issued an opinion which, in 
relevant parts, questioned the constitutionality 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 This 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 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 
geographic and procedural 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 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 reduction 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) CAA Sec. 110(a)(2)(D)(i)(I) as construed by us does not violate 
the 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 SIP Call; and
    (9) We did not violate the Regulatory Flexibility Act.
    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 sell 
electricity to the grid in amounts of either one-third or less of their 
potential electrical output capacity or 25 megawatts or less per year 
(small cogenerators); and
    (4) held that we failed to provide adequate notice of the change in 
control level assumed for large stationary internal combustion engines.

The Court remanded the last two matters for further rulemaking.
5. How Did the Court Respond to EPA's 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.

[[Page 8399]]

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 SIP Call 
and provided that States could submit only those portions of the 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 budget for each State for which the 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\
---------------------------------------------------------------------------

    \1\ October 30, 2000 was the first business day following the 
expiration of the 128-day period.
---------------------------------------------------------------------------

    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 meets the 
NOX SIP Call, these 19 States and the District of Columbia 
may choose to submit SIPs that cover all of the NOX SIP Call 
requirements except for a small part of the EGU portion and large 
internal combustion engine portion of the budget. We refer to these 
partial plans that address the portion of the rule unaffected by the 
Court's remand as the ``Phase I'' SIPs.\2\ Because the 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.
---------------------------------------------------------------------------

    \2\ The Phase I emissions reductions should achieve 
approximately 90 percent of the total emissions reductions called 
for by the NOX SIP Call.
---------------------------------------------------------------------------

6. What Was the Court's Order for the Compliance Date?
    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. This action was in response to a motion filed by the industry/
labor petitioners.

C. What Was 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 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 EGUs \4\ 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-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.
---------------------------------------------------------------------------

    \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 proposing 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 resolve 
a remanded issue related to EGU growth factors.
---------------------------------------------------------------------------

    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)). While the Court has changed the 
NOX SIP Call compliance deadline to May 31, 2004, we 
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). Thus, the automatic 
withdrawal provision in the Section 126 Rule does not address any other 
circumstances. Additional issues regarding the interaction of the 
Section 126 Rule and SIPs under the NOX SIP Call may be 
addressed through future rulemaking.\6\
---------------------------------------------------------------------------

    \6\ A memo dated January 16, 2002 from John Seitz, Director, 
Office of Air Quality Planning and Standards to the EPA Regional Air 
Division Directors, indicated our intent to reset the compliance 
date for EGUs and non-EGUs to May 31, 2004, subject to our response 
to the growth factor remand.
---------------------------------------------------------------------------

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 to us 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 cogenerators 
(cogeneration units that sell electricity to the grid in amounts of 
either one-third or less of their potential electrical output capacity 
or 25 megawatts or less per year). 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 
cogenerators as EGUs. In an order dated on August 24, 2001, the D.C. 
Circuit issued an order in the Appalachian Power--Section 126 Case, 
remanding the Section 126 Rule with regard to the classification of any 
cogenerators as EGUs and tolling (suspending) the date for EGUs to 
implement controls pending EPA's resolution of the EGU growth factor 
remand.
    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 settled these 
cases with several of those sources

[[Page 8400]]

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 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 
cogenerators 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 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 internal 
combustion engines;
    (2) Delayed the NOX SIP Call SIP submittal date to 
October 30, 2000. Michigan (NOX SIP Call);
    (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 of small 
cogenerators as EGUs. Michigan, Appalachian Power-Section 126, 
Appalachian Power-Technical Amendments; and
    (9) Remanded the classification of any cogenerators 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 follows:
    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 
cogenerators or reductions from internal combustion 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 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 fine-
grid 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. A challenge to those findings has 
been filed in the D.C. Circuit.
    Today's action sets forth our proposal for the second phase or 
Phase II of the NOX SIP Call by addressing the 
classification of cogenerators as EGUs, and adjusting the budgets 
accordingly; the control level for large internal combustion engines; 
the date by which States must submit a Phase II budget, and Georgia and 
Missouri must submit SIPs to meet the full NOX SIP Call 
budget; the compliance dates for States to meet their Phase II budgets, 
and for Georgia and Missouri to meet the full NOX SIP Call 
budget; and the emissions budgets for Georgia and Missouri, which are 
proposed to be based on only the fine-grid portion of these States. In 
addition, we propose to modify the budgets for Alabama and Michigan 
based on inclusion of only the fine grid portion of those States. 
Further, we are proposing to exclude Wisconsin from the NOX 
SIP Call.
    Any additional emissions reductions required as a result of a final 
rulemaking on this proposal will be 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 SIP Call. The due date for the SIPs 
meeting the resulting State emissions budgets (``Phase II'' SIPs) and 
partial State budgets for Georgia and Missouri is discussed below in 
sections II.J and II.K. The proposed changes to the State's emissions 
budgets are discussed in section II.E.
    As noted above, today's action proposes to continue the 
classification of cogenerators as EGUs, and presents support for that 
classification.
    In addition, in today's action, we request that cogenerators that 
would be subject to classification as EGUs in the NOX SIP 
Call and the Section 126 Rule identify themselves as cogenerators and, 
if applicable, small generators, so that EPA and the States will be 
able to clarify that portion of their NOX inventory.
    Today's action also includes technical housekeeping by making minor 
revisions to the NOX SIP Call definition of EGUs and non-
EGUs to make those definitions consistent with the definitions of EGUs 
and non-EGUs in

[[Page 8401]]

the Section 126 Rule. Today's proposal retains those definitions in the 
Section 126 Rule.
    Today's proposal does not address the EGU growth remand. We intend 
to act on that issue separately. If any additional revisions to budgets 
are necessary, they will be addressed in that action. By notice dated 
August 3, 2001, we published our preliminary response to the remand in 
which we indicated that we believed our method for estimating growth in 
emissions from EGUs was reasonable, we notified the public that we were 
examining additional data, which we put in the docket, and invited 
comment on that data (66 FR 40609).
    Today's proposal does not address NOX SIP Call issues 
related to the 8-hour NAAQS, and we have no plans in the immediate 
future to announce a specific process for doing so. We have stayed the 
findings in the NOX SIP Call based on the 8-hour NAAQS, and 
are continuing to conduct rulemaking concerning the 8-hour NAAQS.

II. What Is the Scope of This Proposal?

    In this action, we are soliciting comment on only the specific 
changes the Agency is proposing in response to the Court's rulings on 
the NOX SIP Call, Section 126, and Technical Amendments 
rulemakings. We are not reopening the remainder of those three 
rulemakings for public comment and reconsideration. Specifically, we 
are soliciting comment on the following:
    (1) Certain aspects of the definitions of EGU and non-EGU. We are 
not proposing to change the manner in which the budgets are calculated 
for EGUs and non-EGU boilers and turbines under the final 
NOX SIP Call, the Technical Amendments, and the Section 126 
Rules. We also are not proposing to change the definitions of EGU and 
non-EGU used in the Section 126 Rules (e.g., in the allocation 
methodology. We are addressing the issues concerning the definition of 
EGU as applied to certain cogeneration units by proposing 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.
    As part of our treatment of the cogenerator issues, we are 
increasing the required level of emissions reductions, and thus 
reducing the budgets, to require reductions from a set of units--termed 
the non-acid rain units--that we excluded as part of Phase I on grounds 
that they include small cogenerators.
    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 to us their SIP controls at the 
level that was undisturbed by the Court's ruling. Accordingly, we 
determined that the SIPs required to be submitted on the schedule 
established by the Court (October 30, 2000), which we have termed the 
Phase I SIPs, should reflect all reductions required under the 
NOX SIP Call rulemaking except those reductions attributable 
to parts of the rule that the Court remanded or vacated, including 
small cogenerators. However, at the time we adopted this position, we 
were uncertain as to which units constituted small cogenerators, and 
the total emissions attributable to small cogenerators.
    Even so, we were aware that although most of the EGUs that were 
subject to the NOX SIP Call were also controlled under the 
Acid Rain Program, none of the small cogenerators were controlled under 
the Acid Rain Program. (Units controlled under the Acid Rain Program 
may be termed ``acid rain units,'' and those not so controlled may be 
termed ``non-acid rain units.'') 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. As a result, the 
Phase I SIPs may provide for fewer required reductions and higher 
budgets than would have been required if EPA had been able to determine 
which of the non-acid rain units should have been categorized as small 
cogenerators.
    In today's action, we are proposing to continue the classification 
of certain cogenerators, including small cogenerators, as EGUs. As a 
result, it makes sense to require States to include in their Phase II 
SIPs the anticipated emissions reductions from non-acid rain units. 
This approach will have the effect of increasing the SIPs' required 
level of reductions and decreasing the budgets.
    In the final rule, we will indicate the sources we believe should 
be classified as small cogenerators. It is conceivable that this 
process of identifying sources will lead us to conclude that some of 
the non-acid rain units should not be included as EGUs and, therefore, 
that further adjustments to the budgets of particular States may be 
necessary. In this case, we will make those further adjustments in the 
final rule. Because we anticipate that only a small number of sources 
currently meet the definition of small cogenerators, we expect few, if 
any, revisions to the budgets resulting from today's proposal, and if 
any revisions do result, we anticipate that they will be very small and 
will not affect most States.
    We are proposing minor, technical changes to the EGU definition in 
the NOX SIP Call to make it consistent with the definition 
of EGU used in the Section 126 Rule. Since the EGU definition 
establishes the dividing line between the EGU and non-EGU categories, 
the proposed changes to the EGU definition result in corresponding 
proposed changes to the non-EGU definition in the NOX SIP 
Call, which make it consistent with the non-EGU definition in the 
Section 126 Rule. Today's action concerning these definitions does not 
propose any specific revisions to the budgets established under the 
final NOX SIP Call and the Technical Amendments.
    (2) The control level assumed for large stationary internal 
combustion engines in the NOX SIP Call. We are proposing a 
range of possible control levels (82 to 91 percent) to the internal 
combustion engine portion of the budget.
    (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) A range of SIP submission dates for the 19 States and the 
District of Columbia to address the Phase II portion of the budget, and 
for Georgia and Missouri to submit full SIPs meeting the NOX 
SIP Call: 6 months through 1 year from final promulgation of this 
rulemaking, but no later than April 1, 2003.
    (6) The compliance date of May 31, 2004 under the NOX 
SIP Call for all sources except those in Georgia and Missouri, and the 
compliance date of May 1, 2005 for sources in Georgia and Missouri.
    (7) The exclusion of Wisconsin from the NOX SIP Call.

A. How Do We Treat Cogenerators and Non-Acid Rain 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 and large non-EGUs 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'

[[Page 8402]]

budgets, we applied definitions of EGU and non-EGU and determined which 
sources were large EGUs 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 rulemaking 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 with annual electricity sales of one-third or 
less of the units' potential electrical output capacity, or 25 
megawatts (MWe) or less. (A cogeneration unit may be owned by a utility 
or a non-utility and is a unit that uses the same energy to produce 
both thermal energy (heat or steam) that is used for industrial, 
commercial, or heating or cooling purposes; and electricity.) Michigan 
v. EPA, 213 F.3d at 691-92. 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 criteria for the 
exclusion and treating as EGUs those cogeneration units not meeting the 
exclusion 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 the criteria for excluding cogeneration units from 
treatment as utility units. According to the petitioner, the exclusion 
criteria had been established under the regulations implementing new 
source performance standards 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 exclusion 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.

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 
cogenerators as EGUs. The Court held that we had failed to justify this 
classification and base it on adequate record support comparing the 
NOX reduction costs of cogenerators to those of other EGUs 
or demonstrating that there is no relevant physical or technological 
difference between small cogenerators and utilities. In the Section 126 
decision, the Court also remanded our classification of any 
cogenerators as EGUs.
    We discuss below the historical definition of utility unit, the 
definition of EGU in the NOX SIP Call and the Section 126 
rulemaking, today's proposed rule addressing certain aspects of the EGU 
definition, and the rationale for the proposed rule. As discussed 
below, in prior regulatory programs, we have sought to distinguish 
between utilities (regulated monopolies in the business of producing 
and selling electricity) and non-utilities. In making this distinction, 
we applied the ``one third potential electrical output capacity/25 MWe 
sales criteria.'' These criteria defined a non-utility unit as a unit 
producing electricity for annual sales in an amount equal to the lesser 
of: (i) one-third or less of a unit's potential electrical output 
capacity; or (ii) 25 MWe or less. Note that the criteria did not always 
apply only to cogeneration units and did not uniformly result in 
``less'' regulation for sources meeting the criteria. With the 
development of competitive markets for electricity generation and sale, 
we believe that these criteria no longer distinguish between units in 
the business of producing and selling electricity (i.e., EGUs) and non-
EGUs. In addition, there are no relevant differences between the way 
cogenerating units and non-cogenerating units are built and operated 
that justify continuing to use these criteria or that affect the 
general ability of cogenerating units to control NOX. We are 
today proposing to retain the basic definition of EGU in the 
NOX SIP Call and the Section 126 Rule and to continue to 
apply it to cogenerators.
1. What Is the Historical Definition of Utility Unit?
    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 new source performance standards 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 new source performance standards. 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'' which, 
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 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''), 60.40b(a) (stating that subpart Db 
applies to ``steam generating units'' with heat input capacity of more 
than 100 mmBtu/hr), and 60.40b(e) (stating that ``electric steam 
generating units'' subject to subpart Da are not subject to subpart 
Db). Some of the requirements (e.g., the emission limits for 
particulate matter) in subpart D or Db were less stringent than those 
in subpart Da. These criteria applied to all steam generating units, 
not just cogeneration facilities.
    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. We 
believed that a unit involved in electricity sales small enough to be 
at or below the levels in the sales criteria was

[[Page 8403]]

owned by a company whose business was other than electric generation 
and transmission and/or distribution and so was in the industrial, not 
the utility, sector. We stated that, ``[s]ince most industrial 
cogeneration units are expected to be less than 25 MWe electrical 
output capacity, few, if any, new industrial cogeneration units will be 
covered by these [subpart Da] standards. The standards do cover large 
electric utility cogeneration facilities because such units are 
fundamentally electric utility steam generating units.'' Id.
    Our approach in subpart Da reflected the fact that, since before 
the 1970's and into the 1980's, private or public entities in the 
business of electric generation and transmission and/or distribution 
(i.e., utilities) produced almost all of the electricity generated or 
sold in the U.S. In addition, utilities were regulated monopolies with 
designated service areas. In contrast, non-utilities sold relatively 
small amounts of electricity, played an insignificant role in the 
business of electric generation and sales, and were not regulated 
monopolies. See The Changing Structure of the Electric Power Industry: 
An Update, Energy Information Administration, December 1996 at 5-7, 9, 
and 111.
    A similar type of distinction between utility and non-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. 
As noted above, a cogeneration unit is a unit that uses the same energy 
to produce both thermal energy (heat or steam) that is used for 
industrial, commercial, or heating or cooling purposes; and 
electricity. 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). Non-
cogeneration units involved in electricity sales could be utility units 
regardless of whether the non-cogeneration units met one-third 
potential electrical output capacity/25 MWe criteria.
    Finally, 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 hazardous air pollutants 
listed in section 112(b) apply generally to stationary sources. 
However, such emission limits will apply to ``electric utility steam 
generating units'' only if the Administrator makes a specific finding 
after considering the results of a required study. In particular, 
section 112(n)(1)(A) requires the Administrator to study ``the hazards 
to public health reasonably anticipated to occur as a result of 
emissions by electric utility steam generating units'' of the listed 
pollutants ``after imposition of the requirements of [the Clean Air 
Act]'' (42 U.S.C. 7412(n)(1)(A)). That section further provides that 
the Administrator ``shall regulate electric utility steam generating 
units under this section, if the Administrator finds such regulation is 
appropriate and necessary after considering the results of the study.'' 
Id. Thus, in general, cogeneration units excluded from the definition 
of ``electric utility steam generating unit'' are subject by statute--
without any study or finding by the Administrator--to the requirements 
for regulation of hazardous air pollutants under section 112, while 
cogeneration units included in that definition only become subject to 
section 112 based on the Administrator's study and finding supporting 
regulation of units meeting that definition. (See 64 FR 63025, 63030; 
November 18, 1999) (Table 1, showing schedule for promulgation of 
standards for sources (i.e., industrial boilers and institutional/
commercial boilers) of hazardous air pollutants). See also 65 FR 79825, 
December 20, 2001 [Administrator's finding under section 112(n)(1)(A)].
    In summary, the above-described provisions vary as to both: (1) the 
application of the one-third 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'' regulation under some provisions and ``less'' 
or ``later'' regulation under other provisions.
2. What Is 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 of the ``cogeneration exclusion.'' Under 
the methodology applied to all units, after determining the date on 
which a unit commenced operation (e.g., commenced combustion of 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 \7\ for 
classifying all units (including cogeneration units) in the States 
subject to the NOX SIP Call as EGUs or non-EGUs (63 FR 
71223, December 24, 1998). We applied this methodology to cogeneration 
units and not the one-third potential electrical output capacity/25MWe 
sales criteria of the ``cogeneration exclusion.'' See id.
---------------------------------------------------------------------------

    \7\ The numbering of the steps in the methodology is added for 
the convenience of the reader.
---------------------------------------------------------------------------

    (a)(i) For units that commenced operation before January 1, 1996, 
we classified as an EGU any unit that sells 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\
---------------------------------------------------------------------------

    \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 covered by the guaranteed 
commitment to deliver, even under adverse conditions'' (65 FR 2694 
and 2731). As discussed below, we propose to adopt in today's 
proposed rule 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).
---------------------------------------------------------------------------

    (ii) For units that commenced operation before January 1, 1996, we 
classified as a non-EGU any unit that did not produce electricity for 
sale under firm contract to the grid.

[[Page 8404]]

    (iii) For units that commenced operation on or after January 1, 
1996, we classified as an EGU any unit that serves a generator that 
produces any amount of electricity for sale, except as provided in 
paragraph (a)(iv) below.
    (iv) For units that commenced operation on or after January 1, 
1996, we classified as non-EGUs the following units: any unit not 
serving a generator that produces electricity for sale; or any unit 
serving a generator that has a nameplate capacity equal to or less than 
25 MWe, that produces electricity for sale, and that has the potential 
to use 50 percent or less of the usable energy of the boiler or 
turbine. In the December 24, 1998 supplemental action, we did not 
define the term ``usable energy.'' \9\
---------------------------------------------------------------------------

    \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 long-standing definition 
of the latter term as ``33 percent of a unit's maximum design heat 
input'' (65 FR 2694 and 2731). As discussed below, we propose to 
adopt in today's proposed rule 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).
---------------------------------------------------------------------------

    (b)(i) For a unit classified [under paragraph (a)(i) or (a)(iii) 
above] as an EGU, 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\
---------------------------------------------------------------------------

    \10\ In the part 96 model rule in the NOXSIP Call (63 
FR 57356, 57514-38) 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.'' As discussed below, we propose to 
adopt in today's proposed rule 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 Program regulations (40 CFR 72.2).
---------------------------------------------------------------------------

    (ii) For a unit classified [under paragraph (a)(ii) or (a)(iv) 
above] as a non-EGU, 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 71220, 
71224, December 24, 1998 (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\
---------------------------------------------------------------------------

    \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.'' As discussed below, we propose to adopt in today's 
proposed rule the same definition used in the January 18, 2000 
Section 126 final rule.
---------------------------------------------------------------------------

    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 failed to apply this particular exclusion for 
cogenerators that petitioners challenged in Michigan.
3. What Revisions Are Being Made to the Definition of EGU in the 
NOX SIP Call and the Section 126 Rule?
    In today's rulemaking, we are addressing three aspects of the EGU 
definition. First, for purposes of the NOX SIP Call and the 
Section 126 Rule, we are proposing not to apply to cogeneration units 
the one-third potential electrical output/25 MWe sales criteria of the 
``cogeneration exclusion'' in classifying the units as EGUs or non-
EGUs. Under today's proposal, we would apply to all units, including 
cogeneration units, 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. We are proposing to change the categorization of units 
under the NOX SIP Call definition of EGU (set forth in 
section II.A.2 above) as units commencing operation before January 1, 
1996 or units commencing operation on or after January 1, 1996. Under 
today's proposal, we would instead categorize units as units commencing 
operation before January 1, 1997, units commencing operation on or 
after January 1, 1997 and before January 1, 1999, or units commencing 
operation on or after January 1, 1999 for purposes of classifying units 
as EGUs or non-EGUs. 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 and, under today's proposal, units are 
classified the same way as in the January 18, 2000 Section 126 final 
rule. We are also proposing to adopt 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. As noted above, 
these changes to conform to the January 18, 2000 Section 126 Rule do 
not affect the budgets that were established under the final 
NOX SIP Call and the Technical Amendments.
    The only aspects of the EGU definition that we are addressing in 
today's rulemaking are: the use, for cogeneration units, of the 
generally applicable methodology for EGU/non-EGU classification rather 
than the ``cogeneration exclusion'' criteria; the changes in categories 
of units based on commencement of operation date; and the adoption of a 
new term and new definitions of terms. The changes to aspects of the 
EGU definition result in corresponding changes to aspects of the non-
EGU definition. These aspects of the EGU and non-EGU definitions are 
discussed in detail below and are the only issues related to EGU and 
non-EGU definition on which we are requesting comment today. We are not 
reconsidering, and are not taking comment on, any other aspects of the 
EGU or non-EGU definitions.
    a. Use of the same EGU/non-EGU classification methodology for 
cogeneration units as for all other units
    We believe that it is appropriate to apply to cogeneration units 
the same methodology for EGU/non-EGU classification as applied to all 
other units and not to apply the one-third electrical potential output 
capacity/25 MWe sales criteria in order to classify cogeneration units 
as EGUs or non-EGUs. This is appropriate because the reasons for 
distinguishing between utilities and non-utilities no longer exist in 
light of the dramatic changes that have occurred in the electric power 
industry since 1990 due to the emergence of competitive markets for 
electricity generation in which non-utility generators compete to an 
increasingly significant extent with utilities. As a result, the 
historical difference between utilities and non-utilities is 
increasingly blurred and irrelevant in determining what units are 
involved in, and should be classified as, producing and selling 
electricity. In addition, there are no physical, operational, or 
technological differences that warrant use of a different EGU/non-EGU 
classification methodology for cogeneration units than for other units.

[[Page 8405]]

    i. Distinction between units in the electric generation business 
and units in the industrial sector
    As discussed above, distinguishing between units producing 
electricity for sale and units producing electricity for internal use 
or producing steam is a long-standing approach in setting emission 
limits. In the NOX SIP Call, the Section 126 Rule, and 
today's proposal, 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 (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.
    While we are using in today's proposal the long-standing approach 
of distinguishing between units in the electric generation business and 
units in the industrial sector, we are proposing to use the revised 
definition of EGU (i.e., the EGU definition in the Section 126 Rule) in 
order to reflect recent changes in the electric generation business and 
the types of units that currently participate in that business. As 
discussed below, that business is no longer confined essentially to 
utilities, and non-utilities are playing an increasingly significant 
role. We are proposing to define EGU in a way that includes both 
utilities and non-utilities that are in that business and to not apply 
criteria to cogeneration units (i.e., the one third potential 
electrical output capacity/25 MWe sales criteria) that tend to exclude 
non-utilities from the EGU category.
    ii. Effect of electricity competition and electric power 
restructuring on distinction between utilities and non-utilities
    The development of competitive electricity markets is ongoing:

    Propelled by events of the recent past, the electric power 
industry is currently in the midst of changing from a vertically 
integrated and regulated monopoly to a functionally unbundled 
industry with a competitive market for power generation. Advances in 
power generation technology, perceived inefficiencies in the 
industry, large variations in regional electricity prices, and the 
trend to competitive markets in other regulated industries have all 
contributed to the transition. Industry changes brought on by this 
movement are ongoing, and the industry will remain in a transitional 
state for the next few years or more. The Changing Structure of the 
Electric Power Industry: Selected Issues, 1998, Energy Information 
Administration, July 1998 at ix.

See also The Changing Structure of the Electric Power Industry: An 
Update 35-38 (discussing the factors underlying the ongoing development 
of competitive electricity markets and restructuring of the electric 
power industry). Because of the ongoing development of electricity 
markets and electric power industry restructuring, competition in 
electric generation is expected to become more pervasive in the future. 
Electric Power Annual 1998, Vol. II, Energy Information Administration, 
December 1998 at 1 and 4.
    With increased competition and industry restructuring, both 
utilities and non-utilities are generating and selling significant 
amounts of electricity, a trend that is likely to increase in the 
future. In particular, the increasing role of non-utilities is 
reflected in electric power data for the period 1992-1998 indicating 
that:
    (1) The number of investor-owned utilities has decreased by nearly 
8 percent, while the number of non-utilities has increased by over 9 
percent.
    (2) Non-utilities are expanding and buying utility-divested 
generation assets, causing their net generation to increase by 42 
percent and their nameplate capacity to increase by 72 percent from 
1992 to 1998. Non-utility capacity and generation will increase even 
more as they acquire additional utility-divested generation assets over 
the next few years.
    (3) The non-utility share of net generation has risen from 9 
percent (286 million megawatt hours) in 1992 to 11 percent (406 million 
megawatt hours) in 1998.
    (4) Utilities have historically dominated the addition of new 
capacity but additions to capacity by utilities are decreasing while 
additions by non-utilities are increasing. In the period 1985-1991, 
utilities were responsible for 62 percent of the industry's additions 
to capacity, but that figure dropped to 48 percent in the period 1992-
1998. The Changing Structure of the Electric Power Industry 1999: 
Mergers and Other Corporate Combinations, Energy Information 
Administration, December 1999 at x.
    In fact, in 1998 alone, non-utilities accounted for about 11 
percent of net generation and 81 percent of capacity additions. Id. at 
8 (Figure 1); see also id. at 9-10 [Figure 2 (graph showing non-utility 
megawatt additions to capacity far exceeding utility additions) and 
Figure 3 (graph showing non-utility annual growth rate of additions to 
capacity far exceeding utility annual growth rate of additions)]. 
Cogeneration units currently account for about 55 percent of existing 
non-utility capacity, and there is a large potential for more 
cogeneration, e.g., in both the refining and paper and pulp industries. 
Electric Power Annual 1998, Vol. II at 10.
    Along with increases in non-utility generation and capacity, non-
utility sales of electricity to utilities and to end-users have 
increased during 1994-1998, even though the vast majority of 
electricity sales are still made by utilities. Id. at 87 [Table 51 
(showing sales to utilities and end-users)]. With increasing 
competition and restructuring, any unit serving a generator--regardless 
of whether the unit owner is a utility or a non-utility (e.g., an 
independent power producer or an industrial company)--can produce and 
sell electricity. As a result, ``new entrants, generating and selling 
power, have made inroads in an industry previously closed to outside 
participants. Because of this array of changes, the industry is now 
more commonly called the electric power industry rather than the 
erstwhile electric utility industry.'' The Changing Structure of the 
Electric Power Industry: Selected Issues, 1998 at 5. See also The 
Changing Structure of the Electric Power Industry 2000: An Update, 
Energy Information Administration, October 2000 at 1 and Supporting 
Statement for the Electric Power Surveys, OMB Number 1905-0129, Energy 
Information Administration, September 2001 at 7 (discussing the 
continued trend of increased participation of non-utilities in electric 
power industry). Particularly, in light of increasing non-utility 
capacity additions and sales and the likelihood of continued growth in 
non-utility participation in competitive electricity markets, 
distinctions based on ownership of units are becoming less important. 
These distinctions are increasingly irrelevant in determining whether 
units are involved in, and should be classified as, producing and 
selling electricity.
    The Energy Policy Act of 1992 encouraged these types of changes in 
the electric power industry by recognizing a new category of non-
utility generators under the Public Utility Holding Companies Act, 
i.e.,

[[Page 8406]]

``exempt wholesale generators,'' which lack transmission facilities and 
are exempt from the corporate and geographic restrictions imposed by 
the Public Utility Holding Companies Act. Exempt wholesale generators 
may generally charge market-based rates but cannot require utilities to 
purchase the electricity. The Changing Structure of the Electric Power 
Industry: An Update at 28-29. The Energy Policy Act also amended 
section 211 of the Federal Power Act to broaden the ability of non-
utility generators to request that the Federal Energy Regulatory 
Commission (FERC) order utilities to provide transmission services for 
electricity produced and sold by non-utility generators, e.g., 
transmission access to non-contiguous utilities. The Changing Structure 
of the Electric Power Industry: Selected Issues, 1998 at 1. In response 
to the Energy Policy Act, FERC has encouraged competition for 
electricity at the wholesale level (i.e., in sales of electricity for 
resale) by removing obstacles to such competition. For example, 
starting in 1996, FERC issued orders [e.g., Order No. 888, 61 FR 21540 
(1996), and Order No. 889, 61 FR 21737 (1996)] requiring utilities to 
provide open access for electricity generators to transmission lines, 
file nondiscriminatory open-access tariffs applicable to all parties 
seeking transmission service, and participate in the Open Access Same-
Time Information System (OASIS). Id.; see also The Changing Structure 
of the Electric Power Industry: An Update at 57-63 (describing FERC 
Order Nos. 888 and 889). The FERC is continuing to take actions aimed 
at ensuring open transmission access. See, e.g., Order No. 2000, 65 FR 
809 (2000) (requiring utilities to submit proposals for participation 
in a regional transmission organization meeting specified requirements 
aimed at removing impediments to electricity competition or to submit 
any plans to work toward such participation). In short, future Federal 
actions promoting wholesale competition and deregulation of electricity 
generation will likely continue the process of removing the distinction 
between utilities and non-utilities.
    In some States, State actions may also continue this process. Many 
States have adopted legislation or approved plans for, or have begun to 
consider providing, access by end-users to competitive electricity 
markets. A number of States have adopted pilot programs to initiate and 
evaluate the feasibility of competition at the retail level (i.e., in 
sales of electricity to end-users). See Electric Power Annual 1998, Vol 
II at 4; and The Changing Structure of the Electric Power Industry: 
Selected Issues, 1998 at xi and 93. Consequently, ``[o]ne of the 
expectations for the future is that end users of electricity will be 
allowed to participate in a unified wholesale/retail market.'' Id. at 
3. See also The Changing Structure of the Electric Power Industry: An 
Update at 67-68 (describing State actions).
    Other Federal agencies that deal with the power industry have 
realized that the historical distinction between utilities and non-
utilities is no longer meaningful. In particular, the EIA is in the 
process of revising its reporting requirements so that there will be 
virtually no distinction between reporting by utility generators and by 
non-utility generators. Historically, EIA required utilities to report 
electricity generation, fuel use, and other information on different 
forms than non-utilities and treated the utility information as public 
information and the non-utility information as confidential business 
information. Recently, EIA began an effort to reduce, and virtually 
eliminate, the differences between utility and non-utility forms and to 
make most information available to the public. See Electric Power 
Surveys Supporting Statement, EIA, November 1998 at 6, 26, 28-9, 47, 50 
and Supporting Statement for the Electric Power Surveys, OMB Number 
1905-0129 at 16-17, 28, and 30 (explaining that utilities and non-
utilities will be subject to the same data collection and disclosure 
policies).
    In summary, 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 non-utilities. We believe 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.
    iii. Differences between the design and operation of cogenerating 
units and non-cogenerating units
    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 at average costs, similar to those 
achieved by non-cogeneration units. Similarly, 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.
    Cogeneration units operate in two basic configurations.\12\ 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 can be 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 
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.
---------------------------------------------------------------------------

    \12\ 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 # A-96-56, item # 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.
---------------------------------------------------------------------------

    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 can be 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 to the heat recovery steam generator which 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 electrical power. 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 Combined-

[[Page 8407]]

Cycle Product Line and Performance, GE Power Systems, October 2000, 
docket # A-96-56, item 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 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, rather than electricity 
generation.
    Further, in comparison to a non-cogeneration system that generates 
electricity for sale, either type of cogeneration system looks 
essentially the same except for the addition of valves and piping to 
send the steam for process use or heating and cooling. Under 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 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. [For examples and discussion of how post-combustion controls 
apply to cogeneration units, see docket # A-96-56, item # XII-L-02; 
XII-L-03; and XII-L-05 at 10-11 and 13 (Figure 15).]
    More specifically, as discussed in detail in the technical support 
document (Lack of Relevant Physical or Technological Differences 
Between Cogeneration Units and Utility Electricity Generating Units, 
September 25, 2000, docket # A-96-56, item # XII-K-47), 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 above support 
the following conclusions:
    (1) 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 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 systems have been used at a wide range of 
temperatures (e.g., from 1250 degrees F to 2600 degrees F) and have 
been designed to handle a wide range of load variation (e.g., 33 
percent to 100 percent of a unit's maximum continuous rating).
    (2) 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. Selective catalytic reduction has 
been demonstrated on a wide range of boiler types and sizes and on 
combined cycle systems. The SCR systems have been used at a wide range 
of temperatures (e.g., 450 degrees F to 1100 degrees F) and have been 
designed to handle a wide range of load variation.
    Therefore, the same, proven post-combustion NOX control 
technologies (SNCR and SCR) are applicable to non-cogeneration units 
producing electricity for sale and to cogeneration units producing 
electricity for sale. Because no relevant physical, operational, or 
technological differences between these groups of units exist and 
because the post-combustion NOX control technologies are 
located in the same place and operated in the same manner, we maintain 
that there is no significant difference in the average cost of 
controlling NOX emissions from these units.
    For example, 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 # A-96-56, item # V-C-03 at A5-7 (Table 
A5-5). The record also shows that SCR on a new coal-fired cogeneration 
unit has a capital cost of $58 per kilowatt. See Status Report on 
NOX Control Technologies and Cost Effectiveness for Utility 
Boilers, NESCAUM and MARAMA, June 1998, docket # A-96-56, item # VI-B-
05 at 151-53. EPA maintains that this cost is reasonably consistent 
with the average cost that EPA determined for all EGUs.\13\
---------------------------------------------------------------------------

    \13\ 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.
---------------------------------------------------------------------------

    Therefore, we conclude that the cost estimates we made for 
NOX control technology retrofits apply to both cogeneration 
and non-cogeneration units producing electricity for sale. In today's 
rulemaking, we request 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. Any cost information 
that is provided must have sufficient detail and support to allow 
evaluation as to whether the unit involved represents a typical unit.
4. What Methodology Are We Using To Classify EGU/Non-EGU Cogeneration 
Units?
    For the reasons set forth above in section II.A.3 of today's 
preamble, we believe that it is appropriate to use the same methodology 
to classify all units, including cogeneration units, as EGUs or non-
EGUs and generally to classify as EGUs all units that generate 
electricity for sale. This is appropriate regardless of whether the 
owners or operators of the units generating electricity for sale are 
utilities or non-utilities. Since the one-third potential electrical 
output capacity/25 MWe sales criteria of the ``cogeneration exclusion'' 
are essentially proxies for distinguishing between utility and non-
utility ownership of cogeneration units, those criteria are no longer 
appropriate for distinguishing between EGUs and non-EGUs and 
classifying cogeneration units as EGUs or non-EGUs. In addition, as 
also identified in section II.A.3 above, we believe there are no 
relevant physical, operational, or technological differences between 
cogeneration and non-cogeneration units producing electricity for sale.
    However, in order to provide a transition for units commencing 
operation before the development of competitive electricity markets or 
as these markets were emerging, we propose to apply to cogeneration 
units commencing operation before January 1, 1999 a transitional 
criterion for EGU/non-EGU classification. This is the same criterion 
that was used in the September

[[Page 8408]]

24, 1998 NOX SIP Call Rule. Specifically, for cogeneration 
units commencing operation before January 1, 1999, we will classify as 
EGUs units that generate electricity for sale under firm contract to 
the grid. Cogeneration units that generate 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), will be classified 
as non-EGUs. For cogeneration units commencing operation on or after 
January 1, 1999, we will generally classify as EGUs all cogeneration 
units that generate electricity for sale, with the limited exception 
discussed below. As also discussed below, this is the same approach 
that is used for classifying units that are not cogeneration units.
    We believe that the firm-contract criterion provides a reasonable 
transitional means of making the EGU/non-EGU classification for 
cogeneration units. As discussed above, with electricity competition 
and power industry restructuring, the distinction between utility and 
non-utility ownership, and thus the one-third potential electrical 
output capacity/25 MWe sales criteria, no longer provides a relevant 
means of distinguishing between EGUs and non-EGUs. Further, application 
of the one-third potential electrical output capacity/25 MWe sales 
criteria requires historical data for each cogeneration unit on the 
unit's electrical output capacity and electrical sales, all of which 
data has been treated by cogeneration unit owners and EIA as 
confidential business information. We do not have, and the petitioner 
and commenters in the NOX SIP Call and Section 126 
rulemakings have never provided, complete information on the 
identification of all units claiming to be cogeneration units and on 
such units' historical capacity and actual generation and sales.
    In contrast, 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. Moreover, the historical 
information necessary to apply the firm-contract criterion to 
cogeneration units (and other units) is already available to us. As 
discussed above, 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.
    Application of the firm-contract criterion results in classifying, 
as EGUs, cogeneration units that commenced operation before January 1, 
1999 and whose owners have committed to providing electricity for sale 
from the units. This criterion reflects the fact that the amount or 
percentage of the sales (which is a proxy for utility vs. non-utility 
ownership) is no longer relevant for EGU/non-EGU classification. The 
criterion is also practical for us to apply. For cogeneration units 
commencing operation on or after January 1, 1999, we will generally 
classify as EGUs all units generating electricity for sale, regardless 
of whether the sales are sales under firm contract to the grid. The 
category of cogeneration units recently commencing operation is 
relatively small. In the future, EIA will likely be treating virtually 
all new data for both utilities and non-utilities as public 
information, even though EIA will continue to keep historical non-
utility data confidential. We, therefore, believe it is practical for 
us or States to obtain electricity sales information for such 
cogeneration units.
    a. Difference in treatment of cogeneration units that produce 
electricity for sale and those that produce electricity for internal 
use only.
    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 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. EPA notes 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.\14\ As previously 
discussed, this is a long-standing approach that, for the reasons 
presented above, EPA is continuing to use in the NOX SIP 
Call and Section 126 Rule. EPA recognizes that this may result in units 
that are physically identical being regulated differently simply based 
on whether or not electricity produced by the unit is sold. However, 
before abandoning the long-standing approach of distinguishing between 
units on this basis--an action that few, if any, commenters in the 
NOX SIP Call and Section 126 rulemakings have advocated--EPA 
believes that it is prudent to gain experience in operating the trading 
program under the NOX SIP Call and Section 126 Rule. EPA 
proposes to take a reasonable first step to take account of electric 
restructuring and deregulation by revising the definition of EGU to 
focus on production of electricity for sale, regardless of whether a 
unit is a utility or a non-utility. After EPA has gained experience 
with the NOX SIP Call and Section 126 trading program, EPA 
intends to consider whether to take the additional step of treating the 
same all units that produce electricity, whether for sale or internal 
use.
    b. Minor revisions to NOX SIP Call definition of EGU.
    i. As noted above, we propose to change the categorization of units 
used in the NOX SIP Call from units commencing operation 
before January 1, 1996 or units commencing operation on or after 
January 1, 1996 to units commencing operation before January 1, 1997, 
units commencing operation on or after January 1, 1997 and before 
January 1, 1999, or units commencing operation on or after January 1, 
1999. We propose to use these new categories in applying the firm-
contract criterion for EGU/non-EGU classification of all units, 
including cogeneration units. This is a modification of the methodology 
that has been used in the NOX SIP Call. This modification is 
set forth above in section II.A of today's preamble. Under today's 
action, for units commencing operation before January 1, 1997, we 
propose to use the same period (i.e., 1995-1996) to determine the EGU/
non-EGU classification of the units as we used to calculate the EGU 
portion of each State's budget under the NOX SIP Call. See 
63 FR 57407, October 27, 1998. Whether such a unit had electricity 
sales under firm contract to the grid in 1995-1996 will be used to 
determine the unit's EGU/non-EGU classification.
---------------------------------------------------------------------------

    \14\ In fact, use of the one-third potential electrical output 
capacity/25 MWe sales criteria for cogenerators would distinguish 
between EGU cogenerators and non-EGU cogenerators based on the 
cogenerator's amount of electricity sales and would raise the same 
issue. Under these criteria, two physically identical cogenerators 
could have different emission limits simply because one produces and 
sells the requisite amount of electricity and the other produces 
electricity for internal use and does not sell the requisite amount.
---------------------------------------------------------------------------

    For units commencing operation on or after January 1, 1997 and 
before January 1, 1999, we propose to use 1997-1998 to determine the 
EGU/non-EGU classification of units. Whether such a unit had 
electricity sales under firm contract to the grid in 1997-1998 
determines the unit's EGU/non-EGU classification.

[[Page 8409]]

    The firm-contract criterion will not apply to 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 
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.
    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 and the start date 
for applying EGU and non-EGU definitions based on any electricity 
sales. First, information is available to us on firm-contract 
electricity sales on a calendar year basis only. Consequently, the 
classification of units based on whether the generators 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 firm-
contract 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.
    In the interests of reducing the complexity of the regulations 
aimed at reducing interstate transport of ozone, we believe that it is 
desirable to have consistent EGU definitions in the NOX SIP 
Call and Section 126 programs. With the above-described changes in the 
categories of units based on commencement-of-operation date, the EGU 
definition in the NOX SIP Call will be the same as the EGU 
definition reflected in the applicability provisions (i.e., 
Sec. 97.8(a)) of the Section 126 program.
    ii. As noted above, we also propose to use in the 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.
5. What Is the Effect on Cogeneration Unit Classification of Applying 
the Same Methodology as Used for Other Units, Rather Than the One-Third 
Potential Electrical Output Capacity/25 MWe Sales Criteria?
    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 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. This comment and 
the failure of commenters to identify any specific cogeneration units 
affected by today's proposed change suggest that use of the one-third 
potential electrical output capacity/25 MWe sales criteria, instead of 
the classification proposed in today's rule, would shift few, if any, 
existing cogeneration units from being large EGUs to being large or 
small non-EGUs.
    The EGU/non-EGU classification methodology that we propose to use 
for most existing cogeneration units is based on whether, during a 
specified period, the unit served a generator that sold electricity 
under firm contract to the grid. The specified period for units 
commencing operation before January 1, 1997 is 1995-1996, and the 
specified period for units commencing operation on or after January 1, 
1997 and before January 1, 1999 is 1997-1998. Since the EGU/non-EGU 
classification is based on sales under firm contract and not simply 
sales, the methodology proposed for cogeneration units does not 
classify as EGUs all existing cogeneration units that generate 
electricity for sale. We believe that existing cogeneration units that 
are not significantly involved in the business of generating 
electricity for sale will be classified under the proposed methodology 
as non-EGUs, rather than EGUs, because the owners of such units will 
not have committed to providing electricity for sale from the units.
    We request commenters to identify by name, location, and plant and 
point identification any cogeneration unit that commenters believe 
would be classified as an EGU under today's proposed methodology and 
would be classified as a non-EGU if the one-third potential electrical 
output capacity/25 MWe sales criteria were applied instead of the 
proposed methodology. Further, we request that commenters also state 
whether the unit is large or small under each such classification 
approach and provide information about each such unit, supporting any 
claimed EGU, non-EGU, large, and small classifications of the unit.
    While we believe that today's proposed methodology will classify as 
non-EGUs existing cogeneration units that are not significantly 
involved in the business of generating electricity for sale, we request 
information about whether adopting the one-third potential electrical 
output capacity/25 MWe sales criteria, instead of the proposed 
methodology, would change the classification for some cogeneration 
units in a way that would make them potentially subject to more 
stringent emission reduction requirements than under the proposed 
methodology. For example, an existing cogeneration unit classified as a 
large non-EGU under

[[Page 8410]]

today's proposed methodology may become a large EGU if the unit did not 
sell electricity under firm contract to the grid, but sold more than 
one-third of its potential electrical output capacity and serves a 
generator with a nameplate capacity larger than 25 MWe. By further 
example, an existing cogeneration unit classified as a small EGU under 
today's proposed methodology may become a large non-EGU if the unit 
sold electricity under firm contract to the grid, but sold less than 
one-third of its potential electrical output capacity and has a maximum 
design heat input of greater than 250 mmBtu/hr.
    We request commenters to identify by name, location, and plant and 
point identification any cogeneration unit that commenters believe 
would be classified as a large or small non-EGU under today's proposed 
methodology and that would be classified as a large EGU if the one-
third potential electrical output capacity/25 MWe sales criteria were 
applied instead of the proposed methodology. We also request commenters 
to identify by name, location, and plant and point identification any 
cogeneration unit that the commenters believe would be classified as a 
small EGU under today's proposed methodology and that would be 
classified as a large non-EGU if the one-third potential electrical 
output capacity/25 MWe sales criteria were applied instead of the 
proposed methodology. In addition, we request that commenters also 
provide information about each identified unit supporting any claimed 
EGU, non-EGU, large, or small classifications of the unit.
    Sources that identify themselves as cogenerators or small 
cogenerators (one-third potential electrical output capacity/25 MWe 
sales criteria) should submit the following information to assist us in 
confirming 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, sources 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 concerning the unit's maximum design heat input.
    Under today's proposed methodology, the EGU definition based 
generally on whether the unit has any electricity sales will apply to 
units that commence operation on or after January 1, 1999. Thus, in 
general, any new units that serve generators involved in generating 
electricity for sale will be EGUs. This reflects the restructuring of 
the electric power industry under which any unit serving a generator 
(regardless of whether the owner is a utility or a non-utility) can be 
involved in selling electricity and non-utility units are involved in 
an increasing portion of the electricity market. Since we are 
classifying as EGUs cogeneration units that commence operation on or 
after January 1, 1999 and sell any electricity, this may result in 
classification as EGUs of some cogeneration units that recently 
commenced operation or commence operation in the future and that would 
be non-EGUs under the one-third potential electrical output capacity/25 
MWe sales criteria. As discussed above, we maintain that this result is 
reasonable in light of today's changing electricity markets and power 
industry restructuring.

B. What Control Level Is Being Proposed for Stationary Reciprocating 
Internal Combustion Engines (IC Engines)?

1. What Control Level Was Used in the NOX SIP Call?
    In developing budgets for the NOX SIP Call proposal (62 
FR 60318, November 7, 1997), we assumed a 70 percent reduction at large 
sources and reasonably available control technology (RACT) at medium-
sized sources (the OTAG recommendation) for about 20 categories of non-
EGU stationary sources. These sources included, among others, 
industrial boilers and turbines, cement kilns, glass manufacturing, IC 
engines, sand and gravel operations, and steel manufacturing. Once 
State NOX budget components were established for a 
particular option, control strategies were developed for the least-cost 
solution to attain these budgets. The least-cost solution was achieved 
by assuming controls on over 9,000 NOX sources of various 
sizes and categories at an average cost effectiveness of $1,650/ton; 
two thirds of the NOX emissions reductions were from only 
two source categories: non-EGU boilers and IC engines.
    In the final NOX SIP Call Rule, we looked at applying a 
size cut-off for small sources and considered various control levels 
for each of the categories of large non-EGU stationary sources. We 
determined that highly cost-effective controls for non-EGUs were 
appropriate for only three categories: large industrial boilers and 
turbines, cement kilns, and IC engines. For large IC engines, we 
determined, based on the relevant Alternative Control Techniques (ACT) 
document, \15\ that post-combustion controls are available that would 
achieve a 90 percent reduction from uncontrolled levels at costs well 
below $2,000 per ton. Therefore, the budget calculations included a 90 
percent decrease for large IC engines.
---------------------------------------------------------------------------

    \15\ Alternative Control Techniques document, ``NOX 
Emissions from Stationary Reciprocating Internal Combustion 
Engines,'' EPA-453/R-93-032, July 1993.
---------------------------------------------------------------------------

2. What Was the March 3, 2000 Court Decision Regarding IC Engines?
    In the litigation on the NOX SIP Call, the Interstate 
Natural Gas Association of America (INGAA), a trade association that 
represents major interstate natural gas transmission companies in the 
United States, contended that we did not provide adequate notice and 
opportunity to comment on the control level assumed for IC engines in 
its determination of State NOX budgets for the final rule. 
In Michigan v. EPA, 213 F.3d at 693, the Court agreed and remanded this 
issue to us for further consideration.
    The INGAA further contended that the documents that we relied on 
did not support our assumption of 90 percent control level. In 
remanding due to inadequate notice, the Court did not rule on the 
merits of the issue, i.e., the level of control for IC engines.
    In addition, INGAA challenged our definition of ``large'' IC 
engine.\16\ The Court, however, upheld the Agency's definition of large 
IC engine, stating that we went through an extensive comment period on 
this issue. Id. at 693-94.
---------------------------------------------------------------------------

    \16\ A large IC engine is one that emitted, on average, more 
than 1 ton per day during the 1995 ozone season (May 1 through 
September 30).
---------------------------------------------------------------------------

3. What Are the Emissions From IC Engines?
    The large IC engines affected by the NOX SIP Call are 
primarily used in pipeline transmission service with gas turbines at 
compressor stations. Uncontrolled NOX emissions from large 
IC engines are, on average, greater than 3.0 lbs/mmBtu and uncontrolled 
NOX emissions from gas turbines are about 0.3 lbs/mmBtu. In 
the NOX SIP Call, we determined that highly cost-effective 
controls are available to reduce emissions from large IC engines by 90 
percent from uncontrolled levels (i.e., to about 0.3 lbs/mmBtu); \17\ 
and that NOX

[[Page 8411]]

emissions from large gas turbines (and boilers) can be decreased by 
highly cost-effective controls to an average regionwide emission rate 
of 0.15-0.17 lbs/mmBtu. \18\
---------------------------------------------------------------------------

    \17\ The discussion in the text generally uses ``grams/brake 
horsepower-hour'' or g/bhp-hr rather than lbs/mmBtu since the former 
is the convention for the industry. The uncontrolled estimate of 3.0 
lbs/mmBtu (from AP-42, October 1996) corresponds to about 11.3 g/
bhp-hr. The 1993 ACT document for IC engines estimates average 
uncontrolled emissions at 5.13 lb/mmBtu or 16.8 g/bhp-hr.
    \18\ NOX SIP Call Rule at 63 FR 57402.
---------------------------------------------------------------------------

    In the September 24, 1998 final NOX SIP Call Rule, we 
identified about 300 large IC engines. Subsequently, we received 
information from commenters seeking to make changes to the emissions 
inventory. We made corrections to the emissions inventory which now 
includes about 200 large IC engines in the final NOX SIP 
Call budget (65 FR 11222). The vast majority of large IC engines 
included in the budget are natural gas fired.
4. What Control Technologies Are Available for IC Engines?
    For the NOX SIP Call, we divided IC engines into four 
categories and assigned (for purposes of the budget calculation) a 90 
percent emissions decrease on average to each category. The 90 percent 
decrease was based on information in our ACT document for IC engines 
and application of the following controls: non-selective catalytic 
reduction (NSCR) for natural gas-fired rich-burn engines and SCR for 
diesel, dual-fuel, and natural gas-fired lean-burn engines.
    As described in detail in the ACT document, several other control 
technologies are available to decrease emissions of NOX from 
IC engines. For natural gas-fired rich-burn engines, the following 
additional controls exist: air/fuel adjustment, ignition timing retard, 
ignition timing retard plus air/fuel adjustment, prestratified charge, 
and low-emission combustion. For diesel engines, ignition timing retard 
can also be used to reduce emissions of NOX. For dual-fuel 
engines ignition timing retard and low-emission combustion are 
available. Finally, for natural gas-fired lean-burn engines, the 
following additional controls exist: air/fuel adjustment, ignition 
timing retard, ignition timing retard plus air/fuel adjustment, and low 
emission combustion. These controls technologies vary in terms of cost, 
effectiveness, additional fuel needed, and impact on power output.
    The NOX SIP Call budgets were calculated by applying 
controls described in the ACT document for IC engines that represented 
the greatest emissions reductions that would be achieved by applying 
available, highly cost-effective controls. For natural gas-fired rich-
burn IC engines, NSCR provides the greatest NOX reduction of 
all the highly cost-effective technologies considered in the ACT 
document and is capable of providing a 90 to 98 percent reduction in 
NOX emissions. For diesel and dual-fuel engines, SCR 
provides the greatest NOX reduction of all highly cost-
effective technologies considered in the 1993 ACT document and is 
reported to provide an 80 to 90 percent reduction in NOX 
emissions. More recent reports state that NOX emissions can 
be reduced by greater than 90 percent by SCR. Therefore, we estimate 
NOX reductions for these engines at 90 percent on average. 
We estimate the population of diesel/dual fuel IC engines is a very 
small part of the large IC engines population in the NOX SIP 
Call (less than 3 percent).
    In addition to being highly cost effective and providing greater 
emission reductions, the above selected controls generally have the 
advantage of requiring less additional fuel and have less adverse 
impact on power output. For example, ignition retard and air-fuel ratio 
adjustment requires the use of up to 7 percent additional fuel and 
prestratified charge technology may reduce power output up to 20 
percent. In contrast, NSCR and SCR technologies require additional fuel 
in the range of 0.5 to 5 percent and may reduce power output only in 
the 1 to 2 percent range.
    For all large IC engines, except natural gas-fired lean-burn 
engines (see discussion below on lean-burn engines), we continue to 
believe that 90 percent control is achievable through NSCR or SCR and 
is highly cost effective--i.e., less than $2000/ton ozone season. This 
is demonstrated in the ACT document for IC engines and in the IC 
Engines Technical Support Document (TSD) entitled ``Stationary 
Reciprocating Internal Combustion Engines Technical Support Document 
for NOX SIP Call Proposal,'' EPA, OAQPS, September 5, 2000 
(IC Engines TSD). Therefore, we propose to assign a 90 percent 
emissions decrease on average for large natural gas-fired rich-burn, 
diesel, and dual-fuel IC engines. We invite comment on all the control 
technologies listed above, as well as other technologies not listed. 
The appropriate control technology and percent reduction for natural 
gas-fired lean-burn engines is discussed later in this action.
    The time required from a request for cost proposal to field 
installation of proposed NOX controls for IC engines is less 
than 11 months. Therefore, an implementation deadline of May 31, 2004 
is reasonable for States required to adopt and submit Phase II rules no 
later than April 1, 2003, as well as for Georgia and Missouri.
5. Is SCR an Appropriate Technology for Natural Gas-Fired Lean-Burn IC 
Engines?
    Information received by us from the natural gas transmission 
industry after publication of the NOX SIP Call Rule 
indicates that most, if not all, large natural gas-fired lean-burn IC 
engines in the SIP Call region are in natural gas distribution and 
storage service and that these engines experience frequently changing 
load conditions which make application of SCR infeasible. The industry 
also states that low emission combustion (LEC) technology is a proven 
technology for natural gas-fired lean-burn IC engines, while SCR is 
not. Regarding variable load operations, our ACT document for IC 
engines states that little data exist with which to evaluate 
application of SCR for the lean-burn, variable load operations. With 
the understanding that these large IC engines are in variable load 
operations, we now believe there is an insufficient basis to conclude 
that SCR is an appropriate technology for the large lean-burn engines. 
Therefore, we are no longer proposing that SCR is a highly cost-
effective control technology for the natural gas-fired lean-burn IC 
engines. As described in the next section, we believe LEC technology is 
a highly cost-effective control technology and is appropriate for 
natural gas-fired lean-burn IC engines in either variable or continuous 
load operation.
6. Is LEC Technology Appropriate for Natural Gas-Fired Lean-Burn IC 
Engines?
    Lean-burn engines can reduce NOX emissions by adjusting 
the air/fuel ratio to a leaner mode of operation. The increased volume 
of air in the combustion process increases the heat capacity of the 
mixture, lowering combustion temperatures and reducing NOX 
formation. The LEC technology involves a large increase in the air/fuel 
ratio (to ultra-lean conditions) compared to conventional designs.
    Emissions of NOX from existing lean-burn engines can 
vary widely due to the specific air/fuel ratio at which the engine is 
designed to operate. For naturally aspirated engines (which operate at 
near stoichiometric air/fuel ratios), emissions can be as high as 26 
grams per brake horsepower-hour (g/bhp-hr). Turbo-charged engines can 
reduce emissions of NOX up to 40 percent by air/fuel ratio 
increases. Further, engines designed to operate at very high air/fuel 
ratios and with

[[Page 8412]]

advanced ignition technology can reduce emissions to about 1 g/bhp-hr.
    Because there are many types of existing lean-burn engines (e.g., 
some turbo charged, some not), the retrofit of LEC technology would 
require different modifications depending on the particular engine. 
Application of components of LEC technology will yield incremental 
emissions reductions. Therefore, it is important to carefully define 
LEC technology. We propose the following definition, which is similar 
to the description of LEC technology in the ACT document, and invite 
comments on the definition. Implementation of LEC technology for lean-
burn IC engines means:

    The modification of a natural gas-fueled, spark-ignited, 
reciprocating internal combustion engine to reduce emissions of 
NOX by utilizing ultra-lean air-fuel ratios, high energy 
ignition systems and/or pre-combustion chambers, increased turbo 
charging or adding a turbo charger, and increased cooling and/or 
adding an intercooler or aftercooler, resulting in an engine that is 
designed to achieve a consistent NOX emission rate of not 
more than 1.5-3.0 g/bhp-hr at full capacity (usually 100 percent 
speed and 100 percent load).

    The ACT for IC engines and other documents indicate that LEC 
technology is appropriate for lean-burn engines, continuous or variable 
load, and is highly cost effective. We believe application of LEC would 
achieve NOX emission levels in the range of 1.5-3.0 g/bhp-
hr. This is an 82 to 91 percent reduction from the average uncontrolled 
emission levels, on average, reported in the ACT document. We believe 
that LEC retrofit kits are available for all large lean-burn IC 
engines. As described in the IC Engines TSD, emissions test data 
collected over the last several years indicate that 91 percent of IC 
engines with installed LEC technology achieved emission rates of 1.5 g/
bhp-hr or less. A guaranteed level of 2.0 g/bhp-hr is generally 
available from engine manufacturers.
    Because most of the engines tested actually are below 1.5 g/bhp-hr, 
even if some engines in the SIP call area were to exceed the 3.0 level, 
the average emission rate of several engines is still expected to be 
well within the 1.5 to 3.0 range. That is, while engines that are 
equipped with LEC technology designed to meet a 1.5 to 3.0 g/bhp-hr 
standard will generally meet the design goal, the actual results for a 
particular engine may vary. There is one type of engine model, 
Worthington engines, that may be particularly difficult to retrofit and 
which may exceed the 1.5 to 3.0 g/bhp-hr LEC retrofit level. We request 
comment on where and how many large Worthington engines are in the area 
covered by the NOX SIP Call and what average control level 
should be expected with application of LEC technology for those 
engines.
    a. Can States adopt an LEC technology standard?
    States, of course, are not required to adopt technology standard 
rules nor even to adopt rules to control emissions from IC engines. 
However, if States choose to use a technology standard for regulating 
IC engines, we believe it would be appropriate for States to assume an 
average reduction level for each engine installing this technology for 
purposes of calculating the State's emission budget.
    In many cases, we do not suggest a technology-based standard since 
an emission rate and continuous emissions monitoring approach can 
provide more environmental certainty. In this instance, we have data 
identifying the tonnage baseline for each large IC engine, but we do 
not have emission rate (or heat input) data for each IC engine. Thus, 
in order to calculate the budget reduction for IC engines, we must 
identify a percentage reduction and apply that value to the tonnage 
baseline in order to calculate the budget reduction for IC engines. In 
the case of IC engines, a technology standard can be readily translated 
into a percentage reduction. Further, we believe there is a large 
amount of consistent test data supporting LEC technology which provides 
environmental certainty.
    b. What is the cost effectiveness for large IC engines using LEC 
technology?
    For the control range of 82 to 91 percent, the average cost 
effectiveness for large IC engines using LEC technology has recently 
been estimated to be $520 to 550/ton.\19\ We acknowledge that specific 
cost-effectiveness values will vary from engine to engine. The key 
variables in determining average cost effectiveness for LEC technology 
are the average uncontrolled emissions at the existing source, the 
projected level of controlled emissions, annualized costs of the 
controls, and number of hours of operation in the ozone season. The ACT 
document uses an average uncontrolled level of 16.8 g/bhp-hr, a 
controlled level of 2.0 g/bhp-hr, and nearly continuous operation in 
the ozone season. We believe the ACT document provides a reasonable 
approach to calculating cost effectiveness for LEC technology. Further, 
we believe the cost-effectiveness analysis should use updated 
annualized cost data as described in the IC Engines TSD. For additional 
information, we analyzed alternative uncontrolled and controlled 
levels, hours of operation, and annualized costs (see IC Engines TSD). 
The sensitivity analysis indicates a range of cost effectiveness for 
large IC engines using LEC technology of $510 to 870/ton (ozone 
season).
---------------------------------------------------------------------------

    \19\ ``NOX Emissions Control Costs for Stationary 
Reciprocating Internal Combustion Engines in the NOX SIP 
Call States'' prepared by Pechan-Avanti Group for EPA, August 11, 
2000; annual costs in 1990 dollars per NOX tons reduced 
in the ozone season.
---------------------------------------------------------------------------

7. What NOX SIP Call Budget Calculations Are We Proposing?
    We propose to assign a 90 percent emissions decrease on average for 
large natural gas-fired rich-burn, diesel, and dual fuel IC engines. 
For large natural gas-fired lean-burn IC engines, we propose 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 LEC technology, and consideration of 
comments received in response to the proposal, we intend to determine a 
percent reduction number to use in calculating this portion of the 
NOX SIP Call budget decrease; the reduction is likely to be 
within the 82 to 91 percent range. The average cost effectiveness for 
all large IC engines in the SIP Call population is estimated to be 
$530/ton ozone season, where LEC technology is assigned an 87 percent 
reduction and SNCR and SCR achieve 90 percent reduction.\20\ The Agency 
invites comment on the control level and associated cost-effectiveness 
calculations with respect to all IC engine types, and we are especially 
interested in comments regarding the natural gas-fired lean-burn IC 
engines.
---------------------------------------------------------------------------

    \20\ ``NOX Emissions Control Costs for Stationary 
Reciprocating Internal Combustion Engines in the NOX SIP 
Call States'' prepared by Pechan-Avanti Group for EPA, August 11, 
2000.
---------------------------------------------------------------------------

    The NOX SIP Call emissions inventory identifies natural 
gas-fired IC engines, but does not separate rich- and lean-burn IC 
engines. In the final rulemaking, if we choose to use different control 
levels for rich- and lean-burn IC engines, as proposed above, it would 
be necessary to estimate the emissions in each category in order to 
calculate the emissions reductions. We propose to assume that two-
thirds of the emissions from large natural gas-fired IC engines are 
from lean-burn operation and one-third is from rich burn. We invite 
comments on this estimate.

[[Page 8413]]

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

    Georgia and Missouri industry petitioners challenged our decision 
to calculate NOX budgets for these two States based on the 
entirety of NOX emissions in each State. The petitioners 
maintained that the record supports including only eastern Missouri and 
northern Georgia as contributing to downwind ozone. The challenge from 
these petitioners generally stems from the OTAG recommendations. The 
OTAG recommended NOX controls to reduce transport for areas 
within the ``fine grid,'' but recommended that areas within the 
``coarse grid'' not be subject to additional controls, other than those 
required by the CAA. This was based on OTAG's modeling analysis. The 
OTAG recommendation on Utility NOX Controls was approved by 
the Policy Group, June 3, 1997 (62 FR 60318, Appendix B, November 7, 
1997).
    The Court vacated our determination of significant contribution for 
all of Georgia and Missouri. Michigan v. EPA, 213 F.3d at 685. The 
Court did not seem to call into question the proposition that the fine 
grid portion of each State should be considered to make a significant 
contribution downwind. However, the Court emphasized that ``EPA must 
first establish that there is a measurable contribution,'' id. at 684, 
from the coarse grid portion of the State before determining that the 
coarse grid portion of the State significantly contributes to ozone 
nonattainment downwind. Elsewhere, the Court seemed to identify the 
standard as ``material contribution []'' id.
    In its modeling, OTAG used grids drawn across most of the eastern 
half of the United States. The ``fine grid'' has grid cells of 
approximately 12 kilometers on each side (144 square kilometers). The 
``coarse grid'' extends beyond the perimeter of the fine grid and has 
cells with 36 kilometer resolution. The fine grid includes the area 
encompassed by a box with the following geographic coordinates as shown 
in Figure 1, below: Southwest Corner: 92 degrees West longitude, 32 
degrees North latitude; Northeast Corner: 69.5 degrees West longitude, 
44 degrees North latitude (OTAG Final Report, Chapter 2). The OTAG 
could not include the entire Eastern U.S. within the fine grid because 
of computer hardware constraints.
    It is important to note that there were three key factors directly 
related to air quality which OTAG considered in determining the 
location of the fine grid-coarse grid line.\21\ (OTAG Technical 
Supporting Document, Chapter 2, pg. 6; www.epa.gov/ttnotag/otag/finalrpt/). Specifically, the fine grid-coarse grid line was drawn to: 
(1) Include within the fine grid as many of the 1-hour ozone 
nonattainment problem areas as possible and still stay within the 
computer and model run time constraints, (2) avoid dividing any 
individual major urban area between the fine grid and coarse grid, and 
(3) be located along an area of relatively low emissions density. As a 
result, the fine grid-coarse grid line did not track State boundaries, 
and Missouri and Georgia were among several States that were split 
between the fine and coarse grids. Eastern Missouri and northern 
Georgia were in the fine grid while western Missouri and southern 
Georgia were in the coarse grid.
---------------------------------------------------------------------------

    \21\ In addition to these two factors, OTAG considered three 
other factors in establishing the geographic resolution, overall 
size, and the extent of the fine grid. These other factors dealt 
with the computer limitations and the resolution of available model 
inputs.

---------------------------------------------------------------------------

[[Page 8414]]

[GRAPHIC] [TIFF OMITTED] TP22FE02.000

    The analysis OTAG conducted found that emissions controls examined 
by OTAG, when modeled in the entire coarse grid (i.e., all States and 
portions of States in the OTAG region that are in the coarse grid) had 
little impact on high 1-hour ozone levels in the downwind ozone problem 
areas of the fine grid.\22\
---------------------------------------------------------------------------

    \22\ The OTAG recommendation on Major Modeling/Air Quality 
Conclusions approved by the Policy Group, June 3, 1997 (62 FR 60318, 
Appendix B, November 7, 1997).
---------------------------------------------------------------------------

    Based on OTAG's modeling and recommendations, the technical record 
for our final NOX SIP Call rulemaking, and emissions data, 
we believe that emissions in the fine grid portions of Georgia and 
Missouri comprise a measurable or material portion of the entire 
State's significant contribution to downwind nonattainment. 
Specifically, OTAG's technical findings and recommendations state that 
areas located in the fine grid should receive additional controls 
because they contribute to ozone in other areas within the fine grid. 
In addition, we performed State-by-State modeling for Georgia and 
Missouri as part of the final NOX SIP Call rulemaking. The 
results of this modeling show that emissions in both Georgia and 
Missouri make a significant contribution to nonattainment in other 
States. Again, our finding of significant contribution was not 
disturbed by the Court, and the Court stated that the Georgia and 
Missouri industry petitioners challenging the rule did not challenge 
this part of the decision. Michigan v. EPA, 213 F.3d 681-82.
    Examining the 2007 Base Case \23\ NOX emissions for 
Georgia indicates that the amount of NOX emissions per 
square mile in the fine grid portion of the State is over 60 percent 
greater than in the coarse grid part. In Missouri, the amount of 
NOX emissions per square mile in the fine grid portion of 
the State is more than 100 percent greater (i.e., more than double) 
than in the coarse grid part. Moreover, and as the Court pointed out, 
the fine grid portion of each State lies closer to downwind 
nonattainment areas. Michigan v. EPA, 213 F.3d at 683. The OTAG 
concluded from its modeling that the closer an upwind area is to the 
downwind area, the greater the benefits in the downwind area from 
controls in the upwind area.
---------------------------------------------------------------------------

    \23\ The 2007 Base Case includes all control measures required 
by the CAA.
---------------------------------------------------------------------------

    We see no reason to revise the existing determination that sources 
in the fine grid parts of Georgia and Missouri contribute significantly 
to nonattainment downwind. The basis for this determination continues 
to be: (1) The results of EPA's State-by-State modeling; (2) OTAG's 
fine grid-coarse grid modeling; (3) the relatively high amount of 
NOX emissions per square mile in the fine grid portions of 
each State; and (4) the close locations of the fine grid portions of 
each State to downwind nonattainment areas compared to the coarse grid 
part, as described above. We are not making a finding today as to 
whether sources in the coarse grid portions of Georgia and/or Missouri 
make a measurable or material part of the significant contribution of 
each of these States, respectively. In this regard, as with the State 
of Wisconsin described below, we

[[Page 8415]]

will look at the impacts of the coarse grid portions of Georgia and 
Missouri in conjunction with any further analysis on the remaining 15 
OTAG States. In addition, apart from our findings relating to the SIP 
call, a State may, of course, assess the in-State impacts of 
NOX emissions from its coarse grid area, and impose 
additional NOX reductions, beyond the NOX SIP 
Call requirements in the fine grid, as necessary to demonstrate 
attainment or maintenance of the ozone NAAQS in the State.
    We are proposing to revise the NOX budgets for Georgia 
and Missouri to include only the fine grid portions of these States. 
The emissions reductions are therefore required from the fine grid 
portion of the State. For purposes of determining budgets for the fine 
grid portion, we believe that the OTAG longitude and latitude lines 
should be used with an adjustment to account for the fact that some 
counties have a portion of their emissions in both grids (i.e., 
counties that straddle the line separating fine and coarse grids). 
Because of difficulties and uncertainties with accurately dividing 
emissions between the fine and coarse grid of individual counties for 
the purpose of setting overall NOX emissions budgets, we 
believe that the calculation of the emissions budgets should be based 
on all counties which are wholly contained within the fine grid. That 
is, counties which straddle the fine grid-coarse grid line or which are 
completely within the coarse grid are excluded from the budget 
calculations for Georgia and Missouri in today's proposal. The counties 
that we are including in the calculation of NOX budgets for 
each of these States are listed in Table 1.

                              Table 1.--Fine Grid Counties in Georgia and Missouri
----------------------------------------------------------------------------------------------------------------
 
----------------------------------------------------------------------------------------------------------------
Georgia:
    Baldwin                  Effingham                    Jefferson                   Putnam
    Banks                    Elbert                       Jenkins                     Rabun
    Barrow                   Emanuel                      Johnson                     Richmond
    Bartow                   Evans                        Jones                       Rockdale
    Bibb                     Fannin                       Lamar                       Schley
    Bleckley                 Fayette                      Laurens                     Screven
    Bulloch                  Floyd                        Lincoln                     Spalding
    Burke                    Forsyth                      Lumpkin                     Stephens
    Butts                    Franklin                     McDuffie                    Talbot
    Candler                  Fulton                       Macon                       Taliaferro
    Carroll                  Gilmer                       Madison                     Taylor
    Catoosa                  Glascock                     Marion                      Towns
    Chattahoochee            Gordon                       Meriwether                  Treutlen
    Chattooga                Greene                       Monroe                      Troup
    Cherokee                 Gwinnett                     Morgan                      Twiggs
    Clarke                   Habersham                    Murray                      Union
    Clayton                  Hall                         Muscogee                    Upson
    Cobb                     Hancock                      Newton                      Walker
    Columbia                 Haralson                     Oconee                      Walton
    Coweta                   Harris                       Oglethorpe                  Warren
    Crawford                 Hart                         Paulding                    Washington
    Dade                     Heard                        Peach                       White
    Dawson                   Henry                        Pickens                     Whitfield
    De Kalb                  Houston                      Pike                        Wilkes
    Dooly                    Jackson                      Polk                        Wilkinson
    Douglas                  Jasper                       Pulaski
Missouri:
    Bollinger                Iron                         Oregon                      St. Francois
    Butler                   Jefferson                    Pemiscot                    St. Louis
    Cape Girardeau           Lewis                        Perry                       St. Louis City
    Carter                   Lincoln                      Pike                        Scott
    Clark                    Madison                      Ralls                       Shannon
    Crawford                 Marion                       Reynolds                    Stoddard
    Dent                     Mississippi                  Ripley                      Warren
    Dunklin                  Montgomery                   St. Charles                 Washington
    Franklin                 New Madrid                   St. Genevieve               Wayne
    Gasconade
----------------------------------------------------------------------------------------------------------------

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

    We are proposing to calculate Alabama's and Michigan's budgets in 
the same manner as Georgia and Missouri, as described above. While no 
petitioners raised any issues concerning the inclusion of only parts of 
Alabama and Michigan in the NOX SIP Call, the Court's 
reasoning regarding Georgia and Missouri applies equally to Alabama and 
Michigan. Based on the information in the record, we are proposing to 
revise the NOX budgets for Alabama and Michigan to reflect 
reductions only in the fine grid portions of these States. Again, like 
Georgia and Missouri, we see no reason to disturb the determination 
that sources in the fine grid contribute significantly to nonattainment 
downwind. Like Georgia and Missouri, the fine grid portions of both 
Alabama and Michigan are closer to downwind 1-hour ozone nonattainment 
areas than the coarse grid parts of these States. Also, the amount of 
NOX emissions per square mile in the fine grid portion of 
Alabama is nearly 60 percent greater than in the coarse grid part; and 
in Michigan the fine grid NOX emissions per square mile are 
more than 500 percent greater than emissions per square mile in the 
coarse grid portion of this State. Counties in Michigan and Alabama 
which straddle the fine grid-coarse grid are excluded from the budget 
calculations as described above for Georgia and Missouri. The counties 
in Alabama and Michigan that we are including in the calculation of 
NOX

[[Page 8416]]

budgets for each of these States are listed in Table 2.

          Table 2.--Fine Grid Counties in Alabama and Michigan
------------------------------------------------------------------------
 
------------------------------------------------------------------------
Alabama:
    Autauga    Colbert        Greene         Macon           St. Clair
    Bibb       Coosa          Hale           Madison        Shelby
    Blount      Cullman        Jackson        Marion         Sumter
    Calhoun     Dallas         Jefferson      Marshall      Talladega
    Chambers    De Kalb        Lamar          Morgan        Tallapoosa
    Cherokee    Elmore         Lauderdale     Perry          Tuscaloosa
    Chilton     Etowah         Lawrence       Pickens        Walker
    Clay        Fayette        Lee            Randolph      Winston
    Cleburne    Franklin       Limestone      Russell
Michigan
    Allegan     Eaton          Kalamazoo      Monroe         St. Clair
    Barry       Genesee        Kent           Montcalm      St. Joseph
    Bay         Gratiot        Lapeer         Muskegon      Sanilac
    Berrien     Hillsdale      Lenawee        Newaygo        Shiawassee
    Branch      Ingham         Livingston     Oakland        Tuscola
    Calhoun     Ionia          Macomb         Oceana        Van Buren
    Cass        Isabella       Mecosta        Ottawa        Washtenaw
    Clinton     Jackson        Midland        Saginaw        Wayne
------------------------------------------------------------------------

    Today, we are proposing to revise the budgets for Alabama and 
Michigan in the SIP Call regulations to reflect only the fine grid 
portions of those States. As with Georgia and Missouri, the emissions 
reductions are therefore required from the fine grid portion of the 
State. We believe this approach is consistent with the reasoning of the 
Court's March 3, 2000 opinion concerning Georgia and Missouri and is 
justified as provided above.\24\
---------------------------------------------------------------------------

    \24\ Pursuant to the court's order lifting the stay of the SIP 
submission obligation, the 20 States, including Alabama and 
Michigan, were required to submit SIPs in response to the SIP Call 
by October 30, 2000. As discussed above, in letters dated April 11, 
2000 to State Governors, we provided that the States that remained 
subject to the SIP Call could choose to submit SIPs meeting only the 
Phase I emissions budget for each State. With respect to Alabama and 
Michigan, we also provided that Alabama and Michigan could choose to 
submit SIPs that address emissions only in the fine grid portion of 
the State.
---------------------------------------------------------------------------

E. What Modifications Will be Made to the NOX Emissions 
Budgets?

    Today, we are proposing a small change in the statewide emissions 
budgets. We are proposing to calculate the budgets in the same manner 
as the technical amendments (65 FR 11222, March 2, 2000) for purposes 
of defining EGUs. In addition, we are proposing a range of possible 
control levels (82 to 91 percent) for the natural gas-fired lean-burn 
IC engines. For the other IC engine subcategories (natural gas fired 
rich burn, diesel, and dual fuel) we are proposing 90 percent control. 
Because the vast majority of large IC engines are natural gas fired and 
about two-thirds of these are lean-burn, we are applying the 82 and 91 
percent reductions to all large IC engines for the purpose of roughly 
estimating this portion of the proposed budget. Therefore, we are 
proposing to revise the statewide emissions budgets to reflect this 
range of possible control levels. The final budgets will more precisely 
reflect the final rule's breakdown of control percentage per 
subcategory.
    We are proposing to calculate the budgets for Georgia, Missouri, 
Alabama, and Michigan assuming controls in all counties that are fully 
located in the fine grid, as discussed in sections II.C. and II.D. The 
partial State budgets for Georgia, Missouri, Alabama, and Michigan in 
today's action are calculated using 82 percent and 91 percent, as well 
as using the definition of EGUs as described above.
    Our proposed budgets are shown in Tables 3-6. For States that have 
submitted Phase I SIPs, Tables 7 and 8 show the incremental difference 
between Phase I and Phase II budgets. Several States have already 
submitted SIPs that meet the entire budget. However, other States have 
submitted only a Phase I SIP. We propose to require those States to 
supplement their control plans with rules that will meet the proposed 
Phase II increment.

  Table 3.--Proposed State Emissions Budgets and Percent Reduction (82 Percent IC Engine Control & Proposed EGU
                                                   Definition)
                                                  [Tons/season]
----------------------------------------------------------------------------------------------------------------
                                                                        Proposed                       Percent
                       State                           Final base        budget       Tons reduced    reduction
----------------------------------------------------------------------------------------------------------------
Connecticut........................................          46,015          42,850           3,165            7
Delaware...........................................          23,797          22,862             935            4
District of Columbia...............................           6,471           6,658            -187           -3
Illinois...........................................         368,870         271,091          97,779           27
Indiana............................................         340,654         230,381         110,273           32
Kentucky...........................................         237,413         162,519          74,894           32
Maryland...........................................         103,476          81,947          21,529           21
Massachusetts......................................          87,095          84,922           2,173            2
New Jersey.........................................         105,489          96,876           8,613            8
New York...........................................         255,658         240,322          15,336            6

[[Page 8417]]

 
North Carolina.....................................         224,696         165,306          59,390           26
Ohio...............................................         373,222         249,541         123,681           33
Pennsylvania.......................................         345,203         257,928          87,275           25
Rhode Island.......................................           9,463           9,378              85            1
South Carolina.....................................         152,805         123,496          29,309           19
Tennessee..........................................         256,765         198,286          58,479           23
Virginia...........................................         210,786         180,521          30,265           14
West Virginia......................................         176,699          83,921          92,778           53
----------------------------------------------------------------------------------------------------------------


  Table 4.--Proposed State Emissions Budgets and Percent Reduction (91 Percent IC Engine Control & Proposed EGU
                                                   Definition)
                                                  [Tons/season]
----------------------------------------------------------------------------------------------------------------
                                                                        Proposed                       Percent
                       State                           Final base        budget       Tons reduced    reduction
----------------------------------------------------------------------------------------------------------------
Connecticut........................................          46,015          42,850           3,165            7
Delaware...........................................          23,797          22,862             935            4
District of Columbia...............................           6,471           6,658            -187           -3
Illinois...........................................         368,870         270,493          98,377           27
Indiana............................................         340,654         229,913         110,741           33
Kentucky...........................................         237,413         162,242          75,171           32
Maryland...........................................         103,476          81,892          21,584           21
Massachusetts......................................          87,095          84,838         2,257 3
New Jersey.........................................         105,489          96,876           8,613            8
New York...........................................         255,658         240,285          15,373            6
North Carolina.....................................         224,696         164,987          59,709           27
Ohio...............................................         373,222         249,241         123,981           33
Pennsylvania.......................................         345,203         257,551          87,652           25
Rhode Island.......................................           9,463           9,378              85            1
South Carolina.....................................         152,805         123,056          29,749           19
Tennessee..........................................         256,765         198,015          58,750           23
Virginia...........................................         210,786         180,154          30,632           15
West Virginia......................................         176,699          83,822          92,877           53
----------------------------------------------------------------------------------------------------------------


    Table 5.--Proposed Partial State Emissions Budgets and Percent Reduction (82 Percent IC Engine Control &
                                            Proposed EGU Definition)
                                                  [Tons/season]
----------------------------------------------------------------------------------------------------------------
                                                                        Proposed                       Percent
                       State                           Final base        budget       Tons reduced    reduction
----------------------------------------------------------------------------------------------------------------
Georgia............................................         209,914         150,656          59,258           28
Missouri...........................................          92,697          61,433          31,264           34
Alabama............................................         169,156         119,827          49,329           29
Michigan...........................................         245,929         190,908          55,021           22
----------------------------------------------------------------------------------------------------------------


    Table 6.--Proposed Partial State Emissions Budgets and Percent Reduction (91 Percent IC Engine Control &
                                            Proposed EGU Definition)
                                                  [Tons/season]
----------------------------------------------------------------------------------------------------------------
                                                                        Proposed                       Percent
                       State                           Final base        budget       Tons reduced    reduction
----------------------------------------------------------------------------------------------------------------
Georgia............................................         209,914         150,246          59,668           28
Missouri...........................................          92,697          61,403          31,294           34
Alabama............................................         169,156         119,290          49,866           29
Michigan...........................................         245,929         190,860          55,069           22
----------------------------------------------------------------------------------------------------------------


[[Page 8418]]


    Table 7.--Comparison of Phase I and Proposed Phase II State NOX Budgets Comparison (82 Percent IC Engine
                                                    Control)
                                                  [Tons/season]
----------------------------------------------------------------------------------------------------------------
                                                                                                     Phase II
                              State                                   Phase I     Proposed phase    incremental
                                                                      budget        II  budget      difference
----------------------------------------------------------------------------------------------------------------
Alabama.........................................................         124,795         119,827           4,968
Connecticut.....................................................          42,891          42,850              41
Delaware........................................................          23,522          22,862             660
District of Columbia............................................           6,658           6,658               0
Illinois........................................................         278,146         271,091           7,055
Indiana.........................................................         234,625         230,381           4,244
Kentucky........................................................         165,075         162,519           2,556
Maryland........................................................          82,727          81,947             780
Massachusetts...................................................          85,871          84,922             949
Michigan........................................................         191,941         190,908           1,033
New Jersey......................................................          95,882          96,876            -994
New York........................................................         241,981         240,322           1,659
North Carolina..................................................         171,332         165,306           6,026
Ohio............................................................         252,282         249,541           2,741
Pennsylvania....................................................         268,158         257,928          10,230
Rhode Island....................................................           9,570           9,378             192
South Carolina..................................................         127,756         123,496           4,260
Tennessee.......................................................         201,163         198,286           2,877
Virginia........................................................         186,689         180,521           6,168
West Virginia...................................................          85,045          83,921           1,124
----------------------------------------------------------------------------------------------------------------


    Table 8.--Comparison of Phase I and Proposed Phase II State NOX Budgets Comparison (91 Percent IC Engine
                                                    Control)
                                                  [Tons/season]
----------------------------------------------------------------------------------------------------------------
                                                                                                     Phase II
                              State                                   Phase I     Proposed phase    incremental
                                                                      budget        II  budget      difference
----------------------------------------------------------------------------------------------------------------
Alabama.........................................................         124,795         119,290           5,505
Connecticut.....................................................          42,891          42,850              41
Delaware........................................................          23,522          22,862             660
District of Columbia............................................           6,658           6,658               0
Illinois........................................................         278,146         270,493           7,653
Indiana.........................................................         234,625         229,913           4,712
Kentucky........................................................         165,075         162,242           2,833
Maryland........................................................          82,727          81,892             835
Massachusetts...................................................          85,871          84,838           1,033
Michigan........................................................         191,941         190,860           1,081
New Jersey......................................................          95,882          96,876            -994
New York........................................................         241,981         240,285           1,696
North Carolina..................................................         171,332         164,987           6,345
Ohio............................................................         252,282         249,241           3,041
Pennsylvania....................................................         268,158         257,551          10,607
Rhode Island....................................................           9,570           9,378             192
South Carolina..................................................         127,756         123,056           4,700
Tennessee.......................................................         201,163         198,015           3,148
Virginia........................................................         186,689         180,154           6,535
West Virginia...................................................          85,045          83,822           1,223
----------------------------------------------------------------------------------------------------------------

F. How Will the Compliance Supplement Pools Be Handled?

    The compliance supplement pool is a pool of allowances that can be 
used in the beginning of the program to provide affected sources 
additional compliance flexibility in order to address concerns raised 
by commenters on the SIP Call proposal regarding electric reliability. 
In the SIP Call Rule, the compliance supplement pool may be used in the 
years 2003 and 2004 (see 63 FR 57428-57430, October 27, 1998, for 
further discussion of the compliance supplement pool). In Michigan, the 
Court of Appeals for the District of Columbia Circuit ruled that May 
31, 2004, rather than May 1, 2003 is the date by which sources must 
install controls to comply with the SIP Call. Consequently, to be 
consistent with the original 2-year window specified in the SIP Call in 
which we allowed the compliance supplement pool allowances to be used, 
we are extending the time that allowances from the compliance 
supplement pool can be used from September 30, 2004 to September 30, 
2005. We are also proposing to include compliance supplement pools for 
Georgia and Missouri. As under the original NOX SIP Call, 
Georgia and Missouri may distribute the allowances in their respective 
pools either based on early reductions, directly to sources based on a 
demonstrated need, or by some combination of the two methods. (For a

[[Page 8419]]

more complete discussion of how compliance supplement pool allowances 
may be distributed under the NOX SIP call see 63 FR 57429.) 
The allowances from Georgia's and Missouri's compliance supplement 
pools may be used to account for emissions during the first 2 years' 
ozone seasons that sources in those States are required to comply.
    We are not proposing to change the individual State compliance 
supplement pool values that were finalized in the March 2, 2000 
technical corrections to the emission budgets (65 FR 11222) with the 
exception of Alabama, Georgia, Michigan, Missouri, and Wisconsin. 
Changing the State compliance supplement pools to reflect the State 
budget changes made in this action would result in minimal impacts on 
the size of any State's compliance supplement pool. Therefore, we have 
decided to maintain the compliance supplement pools at the levels 
determined in the March 2, 2000 technical amendment (with the exception 
of Alabama, Georgia, Michigan, Missouri, and Wisconsin).
    Since the proposed required reductions in Georgia, Missouri, 
Alabama, and Michigan are less than the required reductions of the 
September 24, 1998 NOX SIP Call reflecting full State 
emissions budgets, we propose to make corresponding decreases to the 
compliance supplement pools for the portion of each State that is still 
subject to the SIP Call. We propose to calculate the partial-State 
compliance supplement pools by prorating the size of the full-State 
compliance pool by the ratio of the reductions that we are proposing 
for the partial-State to the reductions that we required in the March 
2, 2000 Technical Amendment (65 FR 11222). However, to be consistent 
with the way the compliance supplement pool was calculated in the other 
States, we are assuming a 90 percent reduction from IC engines for 
purposes of calculating the compliance supplement pool. In addition, 
since Wisconsin is not being required to make reductions at this time, 
Wisconsin is no longer receiving a share of the compliance supplement 
pool. (Wisconsin's original compliance supplement pool was 6,920 tons.) 
For these reasons, the total compliance supplement pool is now less 
than 200,000 tons. The revised compliance supplement pools for Georgia, 
Missouri, Alabama, and Michigan are shown in Table 9.

                                   Table 9.--Compliance Supplement Pools (CSP)
----------------------------------------------------------------------------------------------------------------
                                                    Full state     Partial state                   Partial state
                                                   tons reduced    tons reduced                     CSP reduced
                                                  (from March 2,    with 90% IC   Full state CSP    with 90% IC
                                                     2000 FR)     engine control                  engine control
----------------------------------------------------------------------------------------------------------------
GA..............................................          63,582          57,623          11,440          10,728
MO..............................................          62,242          31,291          11,199            5630
AL..............................................          64,954          49,806          11,687            8962
MI..............................................          63,118          55,064          11,356            9907
----------------------------------------------------------------------------------------------------------------

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

    In February 1999, Connecticut, Massachusetts, Rhode Island, and EPA 
signed a Memorandum of Understanding (the three-State MOU). The three-
State MOU redistributed Connecticut, Massachusetts, and Rhode Island's 
EGU emissions budgets to minimize the size differential between their 
EGU budgets under the NOX SIP Call and Phase III of the 
Ozone Transport Commission (OTC) NOX Budget program. It also 
reallocated the three States' compliance supplement pools.
    Under the three-State MOU, Connecticut, Massachusetts, and Rhode 
Island would collectively be meeting their NOX SIP Call 
reduction responsibilities because the budget redistribution did not 
result in a higher combined overall EGU budget for the three States. We 
took action to implement the three-State MOU and concurrently published 
proposed and direct final rules on September 15, 1999 (64 FR 50036 and 
49987). We subsequently withdrew the direct final rule on November 1, 
1999 due to the receipt of adverse comment (64 FR 58792). The EGU 
budgets proposed in today's action would not affect the EGU budgets for 
Connecticut, Massachusetts, and Rhode Island that we proposed in 
response to the three-State MOU. We did not finalize the proposal to 
act on the three State MOU. Instead, we proposed to approve the three 
State's NOX SIP call SIP submittals, with budgets that 
reflected the three-State MOU, as collectively meeting their 
NOX SIP call budgets. We did not receive any comments on the 
proposed approval of these three State's SIPs and finalized approval of 
them on December 27, 2000.

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

    We wish to clarify that the use of the term ``budget'' in this 
action does not refer to the transportation conformity rule's use of 
the term ``motor vehicle emissions budget,'' defined at 40 CFR 93.101. 
The budgets proposed today do not set budgets for specific ozone 
nonattainment areas for the purposes of transportation conformity. 
Transportation conformity budgets cannot be tied directly to the SIP 
Call budgets because the latter are for all or a large part of the 
State and the former are nonattainment-area-specific. For nonattainment 
or maintenance areas in a State covered by the SIP Call, transportation 
conformity budgets must reflect the mobile source controls assumed in 
the SIP Call budgets to the extent that the attainment SIP ultimately 
relies upon those controls.

I. How Will Partial-State Trading Be Administered?

    In the final NOX SIP Call, we offered to administer a 
multi-State NOX Budget Trading Program for States affected 
by the NOX SIP Call. In today's action, we are proposing to 
include only partial State budgets for Alabama, Georgia, Michigan, and 
Missouri. Therefore, we are offering to administer a trading program 
for the NOX SIP Call region that, for these four States, 
includes only the portion of the States proposed for inclusion in the 
NOX SIP Call. In the final NOX SIP Call, as well 
as the January 18, 2000 final rulemaking on the original eight Section 
126 petitions, we authorized sources in States affected by either the 
NOX SIP Call or the Section 126 rulemaking to trade with 
each other through the mechanisms of the NOX Budget Trading 
Program provided certain criteria were met. These criteria included 
that States must be subject to the NOX SIP Call and that 
States must meet the emission control level under the final rule for 
the NOX SIP Call. The justification for allowing trading 
across States is the test of

[[Page 8420]]

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

J. What SIP Submittal Dates Are We Proposing?

    In today's action, we are proposing a range of due dates for States 
to submit SIPs meeting the Phase II NOX budgets and the 
partial State budgets for Georgia and Missouri. We believe that the 
appropriate timeframe to consider for SIP submittal is 6 months to 1 
year from final promulgation of this rulemaking but no later than April 
1, 2003, and we request comment on which date within this timeframe is 
appropriate. We believe that a deadline within this range will allow 
adequate time for States to promulgate rules, and for sources affected 
by a State's Phase II NOX strategy and by Georgia and 
Missouri's NOX strategy to comply with the regulations by 
the dates proposed in this action. Please see section K, below, for a 
discussion of the compliance dates.
    In establishing the end of the range, i.e., April 1, 2003, we 
considered the fact that the original NOX SIP Call Rule 
allowed 12 months from the date of promulgation for SIPs to be due. We 
are hopeful that we will finalize this rulemaking in Spring 2002. The 
purpose of having an end date to the range is to ensure that sources 
can comply by the dates discussed below, which will ensure that the 
reductions necessary to minimize ozone transport occur expeditiously.
    We believe that a SIP submittal due date within the proposed range 
would give States adequate time to adopt rules and give sources 
adequate time to install control equipment needed to comply.

K. What Compliance Dates Are We Proposing?

    There are two primary issues that need to be considered when 
determining a reasonable date by which EGUs covered by any Phase II 
SIPs or by SIPs in Georgia and Missouri, can install controls to 
achieve the emissions reductions required:
    (1) How long does it take to complete the design, construction, and 
testing of the controls on large boilers used to generate electricity?
    (2) Does the amount of time that EGUs are taken off-line to install 
controls adversely affect the reliability of the electric power system? 
In other words, does installation of controls reduce the amount of 
available generation to the point where no power can be supplied to 
certain users for a period of time?
    We believe control equipment can generally be applied in an 
expeditious manner. For example, controls on IC engines may be 
installed in less than 1 year. States that choose to control large 
EGUs, however, may experience longer timeframes for installation of 
post-combustion controls. For this reason, we analyzed the timeframe 
required to install controls on large EGUs as part of our decision on 
the appropriate compliance date to set.
    In an effort to remain consistent with the August 30, 2000 Court of 
Appeals' decision regarding the compliance date for Phase I of the 
NOX SIP Call, we are proposing a compliance date of May 31, 
2004 for Phase II sources. We are proposing a May 1, 2005 compliance 
date for affected sources in Georgia and Missouri. We request comment 
on the feasibility of these compliance dates.
    Given a Phase II SIP submittal date as late as April 1, 2003, 
owners and operators of affected units subject to State control 
requirements would have about 13 months, and affected units in Georgia 
and Missouri would have about 25 months to install the necessary 
controls.
    The discussion below supports a Phase II SIP submittal date as late 
as April 1, 2003 for the 19 States and District of Columbia, as well as 
for Georgia and Missouri. Of course, adopting and submitting the SIP 
earlier would provide additional time for the installation of controls.
1. What Is the Technical Feasibility of the Compliance Dates?
    Under Section 126, we issued a final rule determining that sources 
in nine jurisdictions (Delaware, District of Columbia, Maryland, New 
Jersey, North Carolina, Ohio, Pennsylvania, Virginia, and West 
Virginia) and portions of four other jurisdictions (Indiana, Kentucky, 
Michigan, and New York) named in the NOX SIP Call 
significantly contribute to nonattainment in one or more of the 
petitioning States. As finalized by EPA, that rule directly regulated 
sources within the 13 States and required compliance by May 1, 2003 (64 
FR 28250, May 25, 1999 and 65 FR 2674, January 18, 2000). On August 24, 
2001, the D.C. Circuit issued an order in the Appalachian Power-126 
Case, tolling the date for implementing the controls required under the 
Section 126 Rule. Our analysis of the time needed to comply with the 
Phase II rulemaking is still applicable as long as sources are required 
to comply with the Section 126 requirements by May 31, 2004. In 
addition, as part of the OTC NOX Budget Program, the 
remaining Northeast States covered in today's action (Connecticut, 
Massachusetts, New York and Rhode Island) have submitted SIPs, which we 
have approved, to comply by May 1, 2003 with the NOX SIP 
Call.
    We examined the time needed to install the post-combustion controls 
(SCR and SNCR) on large boilers used to generate electricity because 
they represent the most time-consuming NOX control 
retrofits. In this feasibility analysis, we looked at the retrofits we 
projected were needed for affected units in Georgia and Missouri and 
Phase II units in the remaining States to comply with the 
NOX SIP Call. These remaining States include: Alabama, 
Georgia, Illinois, Missouri, South Carolina, and Tennessee and portions 
of Indiana, Kentucky, and Michigan.
    We believe that if States (other than Georgia and Missouri) submit 
SIPs by April of 2003, there is still sufficient time for sources to 
install the necessary controls by May 31, 2004. To determine the amount 
of time involved, we analyzed which sources would reasonably be 
expected to be subject to the Phase II rule. While States may meet the 
requirements of the SIP Call by requiring reductions from any sources 
that are available, most States, as a means of compliance with Phase I 
of the SIP Call, are choosing to require reductions from the same group 
of sources that we considered in determining the budgets. Therefore, we 
believe it is reasonable to assume that States will also regulate, as 
part of their Phase II compliance strategy, the same sources that we 
used to develop the Phase II budgets.
    Our analysis showed that under Phase II, and assuming the multi-
state trading program, three small coal-burning units would elect to 
install SNCR control technology (September 2000 Feasibility memorandum, 
docket # A-96-56, item # XII-K-46). We projected that most of the other 
units would not need to install post-combustion controls because they 
were either already under an emission rate of 0.15 lbs/mmbtu, or they 
were infrequently operated sources that would find it more economical 
to purchase allowances than to install post-combustion control 
equipment. Although installation of SNCR may in some cases be time-
consuming, we believe that these sources will be able to comply by the 
May 31, 2004 compliance date for several reasons. First, we are setting 
emission budgets for the year 2004 based on a 5-month ozone season. 
Because States are required to submit

[[Page 8421]]

SIPs that demonstrate compliance with only a 4-month period in 2004, 
their emission budgets will be larger than needed to meet an emission 
cap of 0.15 lbs/mmbtu in 2004. Therefore, States will have more than 
their sources need to achieve the 0.15 lb/mmBtu level in 2004. The 
States will have flexibility to allocate these allowances recognizing 
that some sources--such as the three sources noted above--may need 
extra time to comply.
    Furthermore, even though we projected that it would take 19 months 
to install SNCR, the actual installation process is projected to take 
only 8 months. The majority of the 19-month installation is related to 
obtaining a construction permit (9 months). Because sources should have 
a strong indication of whether they are going to be regulated under a 
State's Phase II rulemaking before the rulemaking is complete, sources 
could begin this process before a State's rule was finalized. In 
addition, because only a small number of sources are involved, States 
may have opportunities to expedite their construction permitting 
process.
    However, for sources in the fine-grid portions of Georgia and 
Missouri, we propose a May 1, 2005 compliance date. This date will give 
them 25 months to install necessary controls if States submit SIPs by 
April 1, 2003. In Missouri, at most three installations of SNCR are 
projected, or two installations of SCR and one installation of SNCR. In 
Georgia, installations would be not more than seven SNCRs, or two SCRs 
and one SNCR. In our analysis, we projected that two SCRs and one SNCR 
could be installed in less than 25 months and that seven SNCR's could 
be installed in 23 months (September 2000 Feasibility memorandum, 
docket # A-96-56, item # XII-K-46). Furthermore, sources in both 
Georgia and Missouri are already installing some post-combustion 
controls to come into compliance with ozone nonattainment SIPs. In 
addition, because much of the work that will be done in Georgia and 
Missouri will be done after post-combustion controls have been 
installed in many other States, sources in these States will be able to 
take advantage of expertise gained in these other installations to 
reduce the amount of time required to install the controls. For these 
reasons, we believe the May 1, 2005 implementation date is feasible for 
Georgia and Missouri.
    We are also aware that States could choose to utilize the 
compliance supplement pool to assist units that demonstrate a need for 
a longer compliance timeframe, particularly, the small number of units 
in Phase II States that might decide to install post-combustion 
controls. Furthermore, sources could choose to use the trading system 
to help meet these compliance dates, either by purchasing credits from 
other parties or by banking emissions at other units they control and 
using those credits as needed.
2. How Will This Affect Electric Reliability?
    Concerns about electric reliability arise whenever units are down, 
particularly during periods of peak demand. Since units may need to be 
off-line for longer periods of time to install emission controls than 
they normally would be if the units were just being shut down to 
perform other scheduled maintenance, the installation of emission 
controls may increase concerns about reliability. The potential impact 
varies depending on the number of units that have to install controls, 
the additional time that these units have to be taken off-line, and the 
number of units that are off-line at one time.
    We do not anticipate that the installation of NOX 
controls, including SCR, will threaten the reliability of the power 
supply, even during the summer months when the demand for electricity 
is highest. Since SCR is a post-combustion control device that is not 
part of the boiler, most of the SCR retrofit can be constructed while 
the boiler is operating to supply electricity. The boiler needs to be 
turned off only when the SCR is actually connected to the ducts leaving 
the boiler. Owners and operators of electric power plants normally 
schedule connections of these controls during off-peak periods (usually 
spring or fall), when they already plan to shut down the unit to 
perform other scheduled maintenance.
    The EPA and industry groups examined the reliability of the power 
supply in the context of a May 2003 compliance date for the entire 
NOX SIP Call region. Based on these studies, we concluded 
that installation of NOX controls for the entire 
NOX SIP Call region (including Phase I and Phase II affected 
units and affected units in Georgia and Missouri) by May 1, 2003 will 
not threaten the reliability of the electric power supply. Therefore, 
we conclude that providing additional time (an additional year and 1 
month) for the installation of controls on some of the affected units 
further ensures that the reliability of the electric power supply will 
not be threatened by this rule.\25\
---------------------------------------------------------------------------

    \25\ We assumed that sources in States affected under the OTC 
MOU and the Section 126 action will install controls by May 1, 2003, 
but sources in the other States affected by the SIP Call (Alabama, 
Illinois, South Carolina, Tennessee and portions of Indiana, 
Kentucky, and Michigan) will have until May 31, 2004 to install 
controls. In this action, we are proposing that Georgia and Missouri 
will have until May 1, 2005 to install controls. Sources that will 
not have to complete installation of controls until May 31, 2004 
represent approximately 40 percent of the generation capacity in the 
SIP Call Region.
---------------------------------------------------------------------------

    a. Reliability in Georgia and Missouri. In the final NOX 
SIP Call and the final Section 126 Rule, we included the compliance 
supplement pool to address commenters' concerns regarding electricity 
reliability. Therefore, to remain consistent with the intent of the 
original NOX SIP Call, we are proposing to include 
compliance supplement pools for Georgia and Missouri. As under the 
original NOX SIP Call, Georgia and Missouri may distribute 
the allowances in their respective pools either based on early 
reductions, directly to sources based on a demonstrated need, or by 
some combination of the two methods. (For a more complete discussion of 
how compliance supplement pool allowances may be distributed under the 
NOX SIP Call See 63 FR 57429.) The allowances from the pools 
may be used to account for emissions during the first two ozone seasons 
that Georgia and Missouri are required to comply, which under this 
proposal would be in 2005 and 2006. The size of their compliance 
supplement pools have been adjusted to account for the proposed change 
in geographic coverage. See section II.F. of today's action for a 
complete discussion of how the size of Georgia and Missouri's 
compliance supplement pools were calculated.
    With a later compliance date (May 1, 2005 as proposed) than the 
rest of the SIP Call region and the Section 126 region, we believe that 
concerns about the risk to electric reliability due to the installation 
of controls in Georgia and Missouri are not justified. Sources in both 
Georgia and Missouri are expected to install some NOX 
controls before May 1, 2005 as part of the States' ozone attainment 
plans. Furthermore, by May 1, 2005, we expect there to be an active 
NOX allowance market on which sources in Georgia and 
Missouri could rely should they experience an unexpected delay in 
installing controls.

L. What Are We Proposing for Wisconsin?

    In the NOX SIP Call litigation, the Wisconsin industry 
petitioners argued that the emissions from Wisconsin do not contribute 
significantly to nonattainment in any other State. Section 
110(a)(2)(D)(i)(I) requires that a State ``contribute significantly to

[[Page 8422]]

nonattainment in * * * any other State'' in order to be included in the 
challenged SIP Call. 42 U.S.C. 7410(a)(2)(D)(i)(I). The Court held that 
``EPA erroneously included Wisconsin in the NOX SIP Call 
because EPA failed to explain how Wisconsin contributes to 
nonattainment in any other State,'' 213 F.3d at 361 (emphasis in 
original). The Court noted that the record showed only that emissions 
from Wisconsin contribute to violations of the standard over Lake 
Michigan.
    Our ``zero-out'' modeling of Wisconsin emissions using UAM-V shows 
that emissions from Wisconsin impact ozone levels in neighboring 
States, but not during exceedances of the 1-hour NAAQS (i.e., these 
impacts occur when ozone levels are below the NAAQS). For the OTAG 
episodes we modeled, the ozone impacts of Wisconsin on 1-hour 
nonattainment are predicted in the northwestern part of Lake Michigan 
near the shore line of Wisconsin. In the NOX SIP Call 
rulemaking, we concluded that impacts over the lake should be 
considered as contributions to States bordering the lake (i.e., 
Michigan, Indiana, and Illinois) because of lake breeze effects (63 FR 
57386, October 27, 1998). The Court found that we had not provided 
adequate support for this determination and vacated the rule's 
application to Wisconsin for the 1-hour standard (Michigan v. EPA, 213 
F.3d at 681).
    We agree that additional modeling would be necessary in order to 
find that Wisconsin significantly contributes to downwind 1-hour 
nonattainment in any other State and to include Wisconsin in the 
NOX SIP Call at this time. Since we do not currently have 
the modeling necessary to make such a proposal, we intend to exclude 
the entire State of Wisconsin from the requirements of the 1-hour basis 
of the NOX SIP Call to conform to the Court's decision.
    We are not, however, proposing to determine that Wisconsin's 
emissions do not contribute significantly to nonattainment downwind. We 
have not completed the additional modeling analysis for the States that 
are part of the OTAG region but were not included in the final 
NOX SIP Call. In the final NOX SIP Call, we took 
no action on whether emissions from sources in 15 States \26\ in the 
OTAG region do or do not contribute significantly to downwind 
nonattainment, or interfere with maintenance downwind, under either the 
1-hour or the 8-hour ozone NAAQS. We will continue to review available 
information on the downwind impacts of these States. We plan to look at 
the impacts of Wisconsin in conjunction with any further analysis on 
the remaining 15 States. To date, we have stayed the 8-hour basis of 
the SIP Call Rule (65 FR 56245, September 18, 2000) and the Court has 
stayed consideration of the 8-hour basis of the SIP Call Rule. Today's 
action to exclude Wisconsin from the 1-hour basis of the SIP Call does 
not address whether Wisconsin should remain subject to the 8-hour basis 
of the SIP Call. We will address that issue at the time it lifts the 
stay as it applies to Wisconsin.
---------------------------------------------------------------------------

    \26\ Arkansas, Florida, Iowa, Kansas, Louisiana, Maine, 
Minnesota, Mississippi, North Dakota, Nebraska, New Hampshire, 
Oklahoma, South Dakota, Texas, Vermont.
---------------------------------------------------------------------------

M. How Are the 8-Hour NAAQS Rules Affected by This Action?

    As noted above, the revisions to the NOX SIP Call 
proposed in today's action respond to the Court's decision in Michigan 
v. EPA. The Court's decision and today's proposal concern issues 
arising under only the 1-hour ozone NAAQS, and not the 8-hour NAAQS. 
Accordingly, none of the actions proposed today--the definition of EGU 
and the control requirements for IC engines, and implications for the 
State budgets; the SIP submission dates; the revised emissions budgets 
for Alabama, Georgia, Michigan, and Missouri; and the exclusion of 
Wisconsin--if finalized, would have any effect on any requirements of 
the SIP Call on States under the 8-hour NAAQS. Because of the 
litigation concerning the 8-hour ozone NAAQS, we have stayed all of the 
requirements of the SIP Call under the 8-hour NAAQS, ranging from the 
SIP submission dates to the control requirements (65 FR 56245, 
September 18, 2000). After the litigation concerning the 8-hour NAAQS 
is resolved, we will determine whether to proceed with the 8-hour 
requirements under the SIP Call.

III. What Are the Administrative Requirements?

A. Executive Order 12866: Regulatory Impact Analysis

    Under Executive Order 12866 (58 FR 51735, October 4, 1993), the 
Agency must determine whether the regulatory action is ``significant'' 
and, therefore, subject to Office of Management and Budget (OMB) review 
and the requirements of the Executive Order. The Order defines 
``significant regulatory action'' as one that is likely to result in a 
rule that may:
    1. Have an annual effect on the economy of $100 million or more or 
adversely affect in a material way the economy, a sector of the 
economy, productivity, competition, jobs, the environment, public 
health or safety, or State, local, or tribal governments or 
communities;
    2. Create a serious inconsistency or otherwise interfere with an 
action taken or planned by another agency;
    3. Materially alter the budgetary impact of entitlements, grants, 
user fees, or loan programs or the rights and obligations of recipients 
thereof; or
    4. Raise novel legal or policy issues arising out of legal 
mandates, the President's priorities, or the principles set forth in 
the Executive Order.
    This proposed action, which responds to the court decisions in 
Michigan v. EPA, 213 F.3d 663 (D.C. Cir. 2000) (NOX SIP 
Call); Appalachian Power v. EPA, 249 F.3d 1032 (D.C. Cir. 2001) 
(Section 126 Rule), and Appalachian Power v. EPA, 251 F.3d 1026 (D.C. 
Cir. 2001) (NOX SIP Call Technical Amendments), is a 
``significant regulatory action'' under Executive Order 12866 because 
it raises novel legal or policy issues and is, therefore, subject to 
review by OMB.
    Since this is a ``significant regulatory action,'' a Regulatory 
Impact Analysis (RIA) is required. We are using the original RIAs 
prepared for the three actions at issue in the cases listed above 
[``Regulatory Impact Analysis for the NOX SIP Call, FIP, and 
Section 126 Petitions'' (Docket A-96-56)] and [``Regulatory Impact 
Analysis for the Final Section 126 Rule'' (Docket A-97-43)], which 
contain cost and benefit analyses and economic impact analyses 
reflecting requirements of those rules. In addition, we are using an 
update to some of the information in the final NOX SIP Call 
RIA entitled, ``NOX Emissions Control Costs for Stationary 
Reciprocating Internal Combustion Engines in the NOX SIP 
Call States'' (August 11, 2000), an analysis prepared for the IC engine 
portion of this action. This analysis indicates that there is less cost 
incurred per engine than shown in the original RIA which was prepared 
for the final NOX SIP Call. This document is available for 
public inspection in Docket A-96-56 which is listed in the ADDRESSES 
section of this preamble.

B. Executive Order 12898: Environmental Justice

    This action does not involve special consideration of environmental 
justice related issues as required by Executive Order 12898 (59 FR 
7629, February 16, 1994). For the final NOX SIP Call and 
Section 126 Rules, the Agency conducted general analyses of the 
potential changes in ozone and particulate matter levels that may be 
experienced by minority and low-income populations as a result of the 
requirements of these rules. These

[[Page 8423]]

findings were presented in the RIA for each of these rules. Today's 
action does not affect these analyses.

C. Executive Order 13045: Protection of Children From Environmental 
Health Risks and Safety Risks

    Executive Order 13045: ``Protection of Children from Environmental 
Health Risks and Safety Risks'' (62 FR 19885, April 23, 1997) applies 
to any rule that (1) is determined to be ``economically significant'' 
as defined under Executive Order 12866, and (2) concerns an 
environmental health or safety risk that EPA has reason to believe may 
have a disproportionate effect on children. If the regulatory action 
meets both criteria, the Agency must evaluate the environmental health 
or safety effects of the planned rule on children, and explain why the 
planned regulation is preferable to other potentially effective and 
reasonably feasible alternatives considered by the Agency.
    The EPA interprets Executive Order 13045 as applying only to those 
regulatory actions that are based on health or safety risks, such that 
the analysis required under section 5-501 of the Order has the 
potential to influence the regulation. This action is not subject to 
Executive Order 13045 because it does not concern an environmental 
health or safety risk that we have reason to believe may have a 
disproportionate effect on children and it is not economically 
significant under Executive Order 12866.

D. Executive Order 13132: Federalism

    Executive Order 13132, entitled ``Federalism'' (64 FR 43255, August 
10, 1999), requires EPA to develop an accountable process to ensure 
``meaningful and timely input by State and local officials in the 
development of regulatory policies that have federalism implications.'' 
``Policies that have federalism implications'' is defined in the 
Executive Order to include regulations that have ``substantial direct 
effects on the States, on the relationship between the national 
government and the States, or on the distribution of power and 
responsibilities among the various levels of government.'' Under 
section 6 of Executive Order 13132, EPA may not issue a regulation that 
has federalism implications, that imposes substantial direct compliance 
costs, and that is not required by statute, unless the Federal 
government provides the funds necessary to pay the direct compliance 
costs incurred by State and local governments, or EPA consults with 
State and local officials early in the process of developing the 
proposed regulation. The EPA also may not issue a regulation that has 
federalism implications and that preempts State law, unless the Agency 
consults with State and local officials early in the process of 
developing the proposed regulation.
    This proposed action addressing the NOX SIP Call and 
Section 126 Rules does not have federalism implications. It will not 
have substantial direct effects on the States, on the relationship 
between the national government and the States, or on the distribution 
of power and responsibilities among the various levels of government, 
as specified in Executive Order 13132.
    In issuing the SIP Call, EPA acted under section 110(k)(5), which 
requires the Agency to require a State to correct a deficiency that EPA 
has found in the SIP. In October 1998, EPA issued its final SIP Call 
Rule finding that the SIPs for 22 States and the District of Columbia 
were substantially inadequate because they did not regulate emissions 
that significantly contribute to downwind nonattainment in other 
States. On March 3, 2000, the D.C. Circuit largely upheld that rule but 
remanded certain minor issues and vacated and remanded other minor 
issues to the Agency for further consideration. Michigan v. EPA, 213 
F.3d 663 (D.C. Cir. 2000) (NOX SIP Call). Today, EPA is 
proposing action on these remanded and remanded and vacated portions of 
the rule. This action also responds to an issue that the court remanded 
and vacated in the challenge to the NOX SIP Call Technical 
Amendments. Appalachian Power v. EPA, 251 F.3d 1026 (D.C. Cir. 2001) 
(NOX SIP Call Technical Amendments).
    With respect to the proposed action concerning the definition of 
EGU and the level of control for internal combustion engines, the 
proposed action revising the emission budgets for Georgia, Missouri, 
Alabama, and Michigan, and the SIP submission and source compliance 
dates, EPA's proposal does not impose any additional burdens beyond 
those imposed by the final NOX SIP Call. Thus, today's 
action does not alter the relationship established by the final SIP 
Call Rule, which remains in place for 19 States (including Alabama and 
Michigan) and the District of Columbia. Moreover, no aspect of the 
proposed rule changes the established relationship between the States 
and EPA under title I of the CAA. Under title I of the CAA, States have 
the primary responsibility to develop plans to attain and maintain the 
NAAQS. As found by the court, the States have full discretion under the 
SIP Call Rule to choose the control requirements necessary to address 
the transported emissions identified by EPA in the SIP Call.
    As provided in the final action promulgating the SIP Call and the 
Technical Amendments, the SIP Call will not impose substantial direct 
compliance costs. While the States will incur some costs to develop the 
plan, those costs are not expected to be substantial. Moreover, under 
section 105 of the CAA, the Federal government supports the States' SIP 
development activities by providing partial funding of State programs 
for the prevention and control of air pollution. Thus, the requirements 
of section 6 of the Executive Order do not apply to this rule.
    Today's rule also responds to the Court's decision in Appalachian 
Power v. EPA, 249 F.3d 1032 (D.C. Cir. 2001) (Section 126 Rule). This 
action imposes no new requirements that impose compliance burdens 
beyond those that EPA established under the final Section 126 Rule 
(January 18, 2000).

E. Executive Order 13175: Consultation and Coordination With Indian 
Tribal Governments

    Executive Order 13175, entitled ``Consultation and Coordination 
with Indian Tribal Governments'' (65 FR 67249, November 6, 2000), 
requires EPA to develop an accountable process to ensure ``meaningful 
and timely input by tribal officials in the development of regulatory 
policies that have tribal implications.'' ``Policies that have tribal 
implications'' is defined in the Executive Order to include regulations 
that have ``substantial direct effects on one or more Indian tribes, on 
the relationship between the Federal government and the Indian tribes, 
or on the distribution of power and responsibilities between the 
Federal government and Indian tribes.''
    This proposed rule does not have tribal implications. It will not 
have substantial direct effects on tribal governments, on the 
relationship between the Federal government and Indian tribes, or on 
the distribution of power and responsibilities between the Federal 
government and Indian tribes, as specified in Executive Order 13175. 
Today's action does not significantly or uniquely affect the 
communities of Indian tribal governments. The EPA stated in the final 
NOX SIP Call Rule, the Technical Amendments Rule, and the 
Section 126 Rule that Executive Order 13084 did not apply because those 
final rules do not significantly or uniquely affect the communities of 
Indian tribal governments or call on States to regulate NOX 
sources located on tribal lands. The same is true of

[[Page 8424]]

today's action. Thus, Executive Order 13175 does not apply to this 
rule.
    In the spirit of Executive Order 13175, and consistent with EPA 
policy to promote communications between EPA and tribal governments, 
EPA specifically solicits additional comment on this proposed rule from 
tribal officials.

F. Executive Order 13211: Actions Concerning Regulations That 
Significantly Affect Energy Supply, Distribution, or Use

    This summary of the energy impact analysis report estimates the 
energy impacts associated with the Phase II portion of the 
NOX SIP Call, in accordance with Executive Order 13211. It 
covers all EGUs that do not participate in the Acid Rain Trading 
Program and reciprocating internal combustion engines (RICE) in the 
District of Columbia and the 21 States of the NOX SIP Call 
region, as well as all NOX SIP Call sources (cement kilns, 
utility boilers, industrial boilers, combustion turbines, and RICE) in 
the fine grid portions of Georgia and Missouri. In addition, this 
analysis does not consider impacts on sources in the coarse grid 
portions of Michigan and Alabama since these sources are not covered in 
the Phase II rulemaking. The Agency identified applications of control 
devices appropriate for this analysis that provide high levels of 
NOX reduction at relatively low cost, with an average cost 
of less than $2,000 (1990 dollars) per ozone season ton of 
NOX removed, among them: SCR and NSCR, fluid injection 
(steam or ammonia--termed SNCR), and LEC. Through its analysis, the 
Agency identified three relevant energy effects that occur during 
normal operation of these devices: increased energy demands required by 
control devices and equipment, increased energy use due to pressure 
drop and changes in the stoichiometry of the combustion process, and 
energy credits from improved combustion. Each of these NOX 
controls has at least one of these energy effects as part of their 
normal operation.
    The United States consumed over 22 quads (quadrillion Btus) of 
natural gas in 1999.\26\ With respect to energy sources, the 
application of LEC technology to natural gas-driven internal combustion 
(IC) engines amounts to a savings of about 4,000 million British 
thermal units (MMBtus) per unit, or about 70 billion Btus for all 
affected IC engines (about 70 million cubic feet of gas). This amounts 
to about three tenths of one percent of the nation's annual 
consumption. Consequently, the application of LEC technology leads to a 
small savings in natural gas use nationwide by affected sources and 
their firms, but not a large enough savings to affect the price or 
distribution of gas in the United States.
---------------------------------------------------------------------------

    \26\ National Energy Foundation web page: http://www.nef1.org/ea/eastats.html.
---------------------------------------------------------------------------

    The additional coal necessary to compensate for the loss of 
efficiency from SCR and SNCR controls amounts to about 11 MMBtus per 
affected coal-fired boiler, or 89 MMBtus per year per source. For all 
affected utility and industrial coal-fired boilers, this translates to 
slightly more than 70 billion Btus. The United States also consumed 
over 22 quads of coal in 1999. Therefore, the net increase in coal 
consumption necessary for affected boilers to compensate for their 
efficiency loss amounts to about three ten-thousandths of one percent 
of the nation's annual demand for coal. The change in demand for coal 
caused by NOX control efficiency loss will not be of 
sufficient magnitude to affect coal prices. In addition, the reduction 
in electricity output in response to the requirements of the Phase II 
NOX SIP all rulemaking is less than one-half of one percent 
of predicted nationwide output between 2005 and 2010 (to approximate a 
2007 projection). Because utilities constantly adjust their output to 
match demand, and because demand fluctuates more widely than the 
predicted reduction in electricity output from the Phase II rulemaking, 
this report indicates there will be no significant effect on production 
or the factors of production imposed by the NOX SIP Call for 
affected boilers.
    Therefore, we conclude that the proposed rule when implemented is 
not likely to have a significant adverse effect on the supply, 
distribution, or use of energy. For more information on the results of 
this analysis, please consult the energy impact analysis report in the 
public docket for this rule.

G. Unfunded Mandates Reform Act

    Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), Public 
Law 104-4, establishes requirements for Federal agencies to assess the 
effects of their regulatory actions on State, local, and tribal 
governments and the private sector. Under section 202 of the UMRA, 2 
U.S.C. 1532, EPA generally must prepare a written statement, including 
a cost-benefit analysis, for any proposed or final rules with ``Federal 
mandates'' that may result in the expenditure by State, local, and 
tribal governments, in the aggregate, or by the private sector, of $100 
million or more in any 1 year. A ``Federal mandate'' is defined to 
include a ``Federal intergovernmental mandate'' and a ``Federal private 
sector mandate'' (2 U.S.C. 658(6)). A ``Federal intergovernmental 
mandate,'' in turn, is defined to include a regulation that ``would 
impose an enforceable duty upon State, local, or tribal governments,'' 
(2 U.S.C. 658(5)(A)(i)), except for, among other things, a duty that is 
``a condition of Federal assistance'' (2 U.S.C. 658(5)(A)(I)). A 
``Federal private sector mandate'' includes a regulation that ``would 
impose an enforceable duty upon the private sector,'' with certain 
exceptions (2 U.S.C. 658(7)(A)).
    The EPA prepared a statement for the final NOX SIP Call 
that would be required by UMRA if its statutory provisions applied. 
Today's action does not create any additional requirements beyond those 
of the final NOX SIP Call, therefore no further UMRA 
analysis is needed.
    An Unfunded Mandates Analysis was prepared for the proposed Section 
126 Rule which was published on May 25, 1999. The EPA updated this 
analysis for the final Section 126 Rule (January 18, 2000). This 
``Government Entity Analysis for the Final Section 126 Petitions Under 
the Clean Air Act Amendments Title I,'' is available for public 
inspection in Docket A-97-43 which is listed in the ADDRESSES section 
of this preamble. This analysis determined that the final 126 
rulemaking contained no regulatory requirements that might 
significantly or uniquely affect small governments. Today's action 
imposes no new additional requirements above those established in the 
final Section 126 Rule.

H. Regulatory Flexibility Act (RFA), as Amended by the Small Business 
Regulatory Enforcement Fairness Act of 1996 (SBREFA), 5 U.S.C. 601 et 
seq.

    The RFA generally requires an agency to prepare a regulatory 
flexibility analysis for any rule subject to notice and comment 
rulemaking requirements under the Administrative Procedure Act or any 
other statute unless the agency certifies that the rule will not have a 
significant economic impact on a substantial number of small entities. 
Small entities include small businesses, small organizations, and small 
governmental jurisdictions.
    For purposes of assessing the impacts of today's rule on small 
entities, small entity is defined as: (1) A small business as defined 
in the Small Business Administration's (SBA) regulations at 13 CFR 
12.201; (2) a small governmental jurisdiction that is a government of a 
city, county, town, school district or

[[Page 8425]]

special district with a population of less than 50,000; and (3) a small 
organization that is any not-for-profit enterprise which is 
independently owned and operated and is not dominant in its field.
    After considering the economic impacts of today's proposed action 
on small entities, I certify that this action will not have a 
significant economic impact on a substantial number of small entities. 
This proposed action will not impose any requirements on small 
entities. This action responds to the court decisions in Michigan v. 
EPA, 213 F.3d 663, Appalachian Power v. EPA, 249 F.3d 1032 (D.C. Cir. 
2001), and Appalachian Power v. EPA, 251 F.3d 1026 (D.C. Cir. 2001) 
(decisions on the NOX SIP Call, Section 126 Rule, and 
NOX SIP Call Technical Amendments, respectively). The RIA 
for the original final NOX SIP Call included impacts to 
small entities presuming the application of the control strategies we 
modeled as surrogates for what the States would actually employ in 
their NOX SIPs. We also prepared an analysis of impacts to 
small entities affected by the Section 126 Rule. This analysis is 
summarized in the RIA for the final Section 126 Rule and included in 
the docket for that rule. This action does not impose any requirements 
on small entities nor will there be impacts on small entities beyond 
those, if any, required by or resulting from the NOX SIP 
Call and the Section 126 Rules.

I. Paperwork Reduction Act

    Today's action does not add any information collection requirements 
or increase burden under the provisions of the Paperwork Reduction Act 
(44 U.S.C. 3501 et seq.), and therefore is not subject to these 
requirements.

J. National Technology Transfer and Advancement Act

    In addition, the National Technology Transfer and Advancement Act 
of 1997 does not apply because today's proposed action does not require 
the public to perform activities conducive to the use of voluntary 
consensus standards under that Act in the NOX SIP Call, and 
NOX SIP Call Technical Amendments. Today's proposed action 
also does not impose additional requirements over those in the final 
Section 126 Rule. The EPA's compliance with these statutes and 
Executive Orders for the underlying rules, the final NOX SIP 
Call (63 FR 57477, October 27, 1998), the NOX SIP Call 
Technical Amendments (64 FR 26298, May 14, 1999; 65 FR 11222, March 2, 
2000), and the final Section 126 Rule (65 FR 2674, January 18, 2000) is 
discussed in more detail in the citations shown above.
    The EPA is not proposing rule language in today's document. In the 
final rulemaking action in this proceeding, EPA will adopt rule 
language implementing the final action.

List of Subjects

40 CFR Part 51

    Administrative practice and procedure, Air pollution control, 
Environmental protection, Intergovernmental relations, Ozone, Reporting 
and recordkeeping requirements.

40 CFR Part 52

    Air pollution control, Ozone, Reporting and recordkeeping 
requirements.

40 CFR Part 96

    Administrative practice and procedure, Air pollution control, 
Nitrogen oxides, Ozone, Reporting and recordkeeping requirements.

40 CFR Part 97

    Administrative practice and procedure, Air pollution control, 
Intergovernmental Relations, Nitrogen oxides, Ozone, Reporting and 
recordkeeping requirements.

    Dated: February 12, 2002.
Christine T. Whitman,
Administrator.
[FR Doc. 02-3917 Filed 2-21-02; 8:45 am]
BILLING CODE 6560-50-P