[Federal Register Volume 69, Number 77 (Wednesday, April 21, 2004)]
[Rules and Regulations]
[Pages 21604-21648]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 04-7973]



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Part II





Environmental Protection Agency





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40 CFR Parts 51, 78, and 97



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

  Federal Register / Vol. 69, No. 77 / Wednesday, April 21, 2004 / 
Rules and Regulations  

[[Page 21604]]


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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Parts 51, 78, and 97

[FRL-7644-7]
RIN 2060-AJ16


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

AGENCY: Environmental Protection Agency (EPA).

ACTION: Final rule.

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SUMMARY: In today's action, EPA is establishing the final full nitrogen 
oxides (NOX) budgets for States subject to the 
NOX State implementation plan (SIP) Call. This final rule 
requires States that submitted SIPs to meet the Phase I NOX 
SIP Call budgets to submit Phase II SIP revisions as needed to achieve 
the necessary incremental reductions of NOX. It also 
requires Georgia and Missouri to submit SIP revisions meeting the full 
NOX SIP Call budgets since they were not required to submit 
Phase I SIPs. These SIPs are necessary to prohibit specified amounts of 
emissions of NOX--one of the precursors to ozone (smog) 
pollution--for the purposes of reducing NOX and ozone 
transport across State boundaries in the eastern half of the United 
States.
    In today's action, we are amending two related final rules we 
issued under sections 110 and 126 of the Clean Air Act (CAA) related to 
interstate transport of NOX. We are responding to the March 
3, 2000 decision of the United States Court of Appeals for the District 
of Columbia Circuit (DC Circuit) in which the Court largely upheld the 
NOX SIP Call, but remanded four narrow issues to us for 
further rulemaking action; the related decision by the DC 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; the decision by 
the DC 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 DC 
Circuit on August 24, 2001, concerning the Section 126 Rule, in which 
the Court remanded an issue.
    We are also taking final action on modifications that were proposed 
on June 13, 2001 to the Appeal Procedures and to the Federal 
NOX Budget Trading Program. Today's final rule completes 
action on the June 13, 2001 proposed rule revisions for sources subject 
to the Federal NOX Budget Trading Program under the Section 
126 final rule.
    The specific issues addressed in this action are described below 
under SUPPLEMENTARY INFORMATION.

DATES: This rule is effective June 21, 2004.

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 
[email protected]. Technical questions concerning electric generating 
units (EGUs) should be directed to Kevin Culligan, Office of 
Atmospheric Programs, Clean Air Markets Division, (6204M), 1200 
Pennsylvania Ave., NW., Washington, DC 20460, telephone (202) 564-9172, 
e-mail [email protected]; technical questions concerning 
stationary internal combustion (IC) engines should be directed to Doug 
Grano, Office of Air Quality Planning and Standards, C539-02, Research 
Triangle Park, North Carolina 27711, telephone (919) 541-3292, e-mail 
[email protected]; legal questions should be directed to Winifred 
Okoye, Office of General Counsel, (2344A), 1200 Pennsylvania Ave., NW., 
Washington, DC 20460, telephone (202) 564-5446, e-mail 
[email protected].

SUPPLEMENTARY INFORMATION: 

I. General Information

    A. Today's action addresses the issues remanded or vacated by the 
DC Circuit in Michigan v. EPA, 213 F.3d 663 (DC 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 (DC 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 (DC 
Cir. 2001).
    Today's action establishes the second phase or Phase II of the 
NOX SIP Call by:
    (1) Finalizing the definition of EGU as applied to certain small 
cogeneration units,
    (2) Setting the control levels for stationary IC engines,
    (3) Excluding portions of Georgia, Missouri, Alabama and Michigan 
from the NOX SIP Call,
    (4) Revising statewide emissions budgets in the NOX SIP 
Call to reflect the disposition of the first three issues above,
    (5) Setting a SIP submittal date,
    (6) Setting the compliance date for implementation of control 
measures, and
    (7) Excluding Wisconsin from NOX SIP Call requirements.
    For more detailed discussions of the issues addressed in this 
action, see section II below.
    Ground-level ozone has long been recognized to affect public 
health. Ozone induces health effects, including decreased lung function 
(primarily in children active outdoors), increased respiratory symptoms 
(particularly in highly sensitive individuals), increased hospital 
admissions and emergency room visits for respiratory causes (among 
children and adults with pre-existing respiratory disease such as 
asthma), increased inflammation of the lungs, and possible long-term 
damage to the lungs. Each year, ground-level ozone is also responsible 
for crop yield losses. Ozone also causes noticeable foliar damage in 
many crops, trees, and ornamental plants (i.e., grass, flowers, shrubs, 
and trees) and causes reduced growth in plants. Studies indicate that 
current ambient levels of ozone are responsible for damage to forests 
and ecosystems (including habitat for native animal species).
    B. How Can I Get Copies of Related Information?
    1. Docket. EPA has established an official public docket for this 
action under Docket ID No. OAR-2001-0008; it has also been incorporated 
by reference in the docket for the Section 126 Rule under Docket ID No. 
OAR-2001-0009. The official public docket consists of the documents 
specifically referenced in this action, any public comments received, 
and other information related to this action. Although a part of the 
official docket, the public docket does not include Confidential 
Business Information (CBI) or other information whose disclosure is 
restricted by statute. Documents in the official public docket are 
listed in the index list in EPA's electronic public docket and comment 
system, EDOCKET. Documents may be available either electronically or in 
hard copy. Electronic documents may be viewed through EDOCKET. Hard 
copy documents may be viewed at the Air Docket in the EPA Docket 
Center, (EPA/DC) EPA West, Room B102, 1301 Constitution Ave., NW., 
Washington, DC. The EPA Docket Center Public Reading Room is open from 
8:30 a.m. to 4:30 p.m., Monday through Friday, excluding legal 
holidays. The telephone number for the Public Reading Room is (202) 
566-1744, and the telephone

[[Page 21605]]

number for the Air Docket is (202) 566-1742; fax (202) 566-1741. A 
reasonable fee may be charged for copying.
    2. Electronic Access. You may access this Federal Register document 
electronically through the EPA Internet under the ``Federal Register'' 
listings at http://www.epa.gov/fedrgstr/ or the federal wide 
eRulemaking site at http://www.regulations.gov.
    An electronic version of the public docket is available through 
EDOCKET. You may use EDOCKET at http://www.epa.gov/edocket/ to view 
public comments, access the index listing of the contents of the 
official public docket, and to access those documents in the public 
docket that are available electronically. Publicly available docket 
materials that are not available electronically may be viewed at the 
docket facility identified in Unit I.B. Once in the system, select 
``search,'' then key in the appropriate docket identification number.

Public Hearing

    We held a public hearing in Washington, DC on March 15, 2002. Four 
people presented comments at the hearing. The public also had an 
opportunity to submit written testimony within approximately 45 days 
after the hearing date.

Outline

I. Background
    A. What Was Contained in the NOX SIP Call?
    B. What Were the Court Decisions on the NOX SIP Call?
    1. What Was the Decision of the Court on the 8-Hour Ozone NAAQS?
    2. What Effect Did the Court Decision Have on the 8-Hour Portion 
of the NOX SIP Call?
    3. What Was the DC Circuit Decision on the Stay of the SIP 
Submittal Schedule for the NOX SIP Call?
    4. What Was the Court's Decision on the NOX SIP Call?
    5. How Did the Court Respond to Our Request To Lift the Stay of 
the 1-Hour SIP Submission Schedule?
    6. What Was the Court's Order for the Compliance Date?
    C. What Was Contained in the Section 126 Rule?
    1. What Was the DC Circuit Decision on the Section 126 Rule?
    D. What Were the Technical Amendments Rulemakings?
    1. What Was the DC Circuit Decision on the Technical Amendments?
    E. What Is the Overview of DC Circuit Remands/Vacaturs?
    F. What Is Our Process for Addressing the Remands/Vacaturs?
II. What Is the Scope of this Action?
    A. How Do We Treat Cogeneration Units and Non-Acid Rain Units?
    1. What Is the Historical Definition of Utility Unit?
    2. What Was the NOX SIP Call Definition of EGU?
    3. What Is the Rationale for the Final Rule's Treatment of 
Cogeneration Units?
    4. What Revisions Are Being Made to the Definition of EGU in the 
NOX SIP Call and the Section 126 Rule?
    5. What Is the Effect on Cogeneration Unit Classification of 
Applying ``One-Third Potential Electrical Output Capacity/25 MWe 
Sales'' Criteria, Rather Than the Same Methodology as Used for Other 
Units?
    B. What Are the Control Levels and Budget Calculations for 
Stationary Reciprocating Internal Combustion Engines (IC Engines)?
    1. Determination of Highly Cost-Effective Reductions and Budgets
    2. What Are the Key Comments We Received Regarding IC Engines?
    C. What Is Our Response to the Court Decision on Georgia and 
Missouri?
    D. What Are We Finalizing for Alabama and Michigan in Light of 
the Court Decision on Georgia and Missouri?
    E. What Modifications Are Being Made to the NOX 
Emissions Budgets?
    F. How Will the Compliance Supplement Pools Be Handled?
    G. Will the EGU Budget Changes Affect the States Included in the 
Three-State Memorandum of Understanding?
    H. How Does the Term ``Budget'' Relate to Conformity Budgets?
    I. How Will Partial-State Trading Be Administered?
    1. How Will Flow Control Be Handled for Georgia and Missouri?
    J. What Is the Phase II SIP Submittal Date?
    K. What Are the Phase II Compliance Dates?
    1. How Are We Handling Non-Acid Rain EGUs and Any Cogeneration 
Units That Were Previously Classified as EGUs, and Whose 
Classification Changed to Non-EGUs Under Today's Rule?
    2. What Compliance Date Are We Finalizing for IC Engines and 
What Is the Technical Feasibility of This Date?
    3. What Compliance Date Are We Finalizing for Georgia and 
Missouri?
    L. What Action Are We Taking on Wisconsin?
    M. How Are the 8-Hour Ozone NAAQS Rules Affected by This Action?
    N. What Modifications Are Being Made to Parts 51, 78, and 97?
III. Statutory and Executive Order Reviews
    A. Executive Order 12866: Regulatory Planning and Review
    B. Paperwork Reduction Act
    C. Regulatory Flexibility Act (RFA)
    D. Unfunded Mandates Reform Act
    E. Executive Order 13132: Federalism
    F. Executive Order 13175: Consultation and Coordination with 
Indian Tribal Governments
    G. Executive Order 13045: Protection of Children From 
Environmental Health and Safety Risks
    H. Executive Order 13211: Actions That Significantly Affect 
Energy Supply, Distribution, or Use
    I. National Technology Transfer Advancement Act
    J. Executive Order 12898: Federal Actions To Address 
Environmental Justice in Minority Populations and Low-Income 
Populations
    K. Congressional Review Act

I. Background

A. What Was Contained in the NOX SIP Call?

    By notice dated October 27, 1998 (63 FR 57356), we took final 
action to prohibit specified amounts of emissions of one of the main 
precursors of ground-level ozone, NOX, in order to reduce 
ozone transport across State boundaries in the eastern half of the 
United States. Based on extensive air quality modeling and analyses, we 
found that sources in 22 States and the District of Columbia (DC) (23 
States) emit NOX in amounts that significantly contribute to 
nonattainment of the 1-hour ozone national ambient air quality 
standards (NAAQS) in downwind States. We set forth requirements for 
each of the affected upwind States to submit SIP revisions prohibiting 
those amounts of NOX emissions which significantly 
contribute to downwind air quality problems. We established statewide 
NOX emissions budgets for the affected States. The budgets 
were calculated by assuming the emissions reductions that would be 
achieved by applying available, highly cost-effective controls to 
source categories of NOX. States have the flexibility to 
adopt the appropriate mix of controls for their State to meet the 
NOX emissions reductions requirements of the NOX 
SIP Call. A number of parties, including certain States as well as 
industry and labor groups, challenged our NOX SIP Call Rule.
    Independently, we also found that sources and emitting activities 
in 22 States and the District of Columbia emit NOX in 
amounts that significantly contribute to nonattainment of the 8-hour 
ozone NAAQS. In response to the court decisions, on September 18, 2000 
(65 FR 56245), we stayed the findings in the NOX SIP Call 
based on the 8-hour ozone NAAQS. However, we are evaluating the process 
for lifting the stay in light of recent EPA actions on the 8-hour ozone 
standard.

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

1. What Was the Decision of the Court on the 8-Hour Ozone NAAQS?
    On May 14, 1999, the DC 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

[[Page 21606]]

F.3d 1027 (DC 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 DC Circuit granted in part and denied in 
part our rehearing request. American Trucking Ass'n v. EPA, 194 F.3d 4 
(DC 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 DC 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 DC Circuit to 
consider challenges to the revised ozone NAAQS on other grounds.
2. What Effect Did the Court Decision Have on the 8-Hour Portion of the 
NOX SIP Call?
    The litigation created uncertainty with respect to our ability to 
rely upon the 8-hour ozone standards as an alternative basis for the 
NOX SIP Call. As a result, we stayed indefinitely the 
findings of significant contribution 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 DC 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 DC Circuit 
issued a stay of the SIP submission deadline pending further order of 
the Court. Michigan v. EPA, 213 F.3d 663 (DC 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 DC Circuit issued its decision on the 
NOX SIP Call, ruling in our favor on the issues that 
affected the rulemaking as a whole, but ruling against us on several 
issues. Michigan v. EPA, 213 F.3d 663 (DC Cir. 2000). The Court's 
decision in Michigan v. EPA, 213 F.3d 663 (DC 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 emissions 
reductions as part of the determination of significant contribution is 
consistent with the statute and judicial precedent;
    (5) Our scheme of uniform emissions reductions requirements is 
reasonable;
    (6) Our interpretation of CAA section 110(a)(2)(D)(i)(I) does not 
violate the nondelegation doctrine;
    (7) We did not intrude on the statutory rights of States to fashion 
their SIPs;
    (8) We properly included South Carolina in the NOX SIP 
Call; and
    (9) We did not violate the Regulatory Flexibility Act (RFA).
    However, the Court ruled against us on four specific issues. 
Specifically, the Court:
    (1) Remanded and vacated the inclusion of Wisconsin because 
emissions from Wisconsin did not show a significant contribution to 
downwind nonattainment of the NAAQS;
    (2) Remanded and vacated the inclusion of Georgia and Missouri in 
light of the Ozone Transport Assessment Group (OTAG) conclusions that 
emissions from coarse grid portions did not merit controls;
    (3) Held that we failed to provide adequate notice of the change in 
the definition of EGU as applied to cogeneration units that supply 
electricity to a utility power distribution system for sale in amounts 
of either one-third or less of their potential electrical output 
capacity or 25 megawatts or less per year (small cogeneration units); 
and
    (4) Held that we failed to provide adequate notice of the change in 
control level assumed for large stationary IC engines.
    The Court remanded the last two matters for further rulemaking.
5. How Did the Court Respond To Our Request To Lift the Stay of the 1-
Hour SIP Submission Schedule?
    On April 11, 2000, we filed a motion with the Court to lift the 
stay of the SIP submission date. We requested that the Court lift the 
stay as of April 27, 2000. We recognized, however, that at the time the 
stay was issued, States had approximately 4 months (128 days) remaining 
to submit SIPs. Therefore, our motion to lift the stay indicated that 
we would allow States until September 1, 2000 to submit SIPs addressing 
the NOX SIP Call and provided that States could submit only 
those portions of the NOX SIP Call upheld by the Court 
(Phase I SIPs). The existing record in the NOX SIP Call 
rulemaking provides a breakdown of the data on which the original 
budgets were developed sufficient to allow States to develop Phase I 
SIPs. However, we reviewed the record and for the convenience of the 
States and in letters to the State Governors and State Air Directors, 
dated April 11, 2000, we identified an adjusted Phase I NOX 
budget for each State for which the NOX SIP Call applies.
    On June 22, 2000, the Court granted our request in part. The Court 
ordered that we allow the States 128 days from the June 22, 2000 date 
of the order to submit their SIPs. Therefore, SIPs in response to the 
NOX SIP Call were due October 30, 2000.\1\
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    \1\ October 30, 2000 was the first business day following 
expiration of the 128-day period.
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    In our motion to lift the stay, we informed the Court that the 
Agency asked 19 States and the District of Columbia, in letters to the 
Governors dated April 11, 2000, to submit SIPs subject to the Court's 
response to our motion to lift the stay. The 19 States are: Alabama, 
Connecticut, Delaware, Illinois, Indiana, Kentucky, Massachusetts, 
Maryland, Michigan, North Carolina, New Jersey, New York, Ohio, 
Pennsylvania, Rhode Island, South Carolina, Tennessee, Virginia and 
West Virginia. Rather than submit a SIP that fully met the 
NOX SIP Call, we allowed these 19 States and the District of 
Columbia to submit SIPs that cover all of the NOX SIP Call 
requirements except for a small part of the EGU portion and large IC 
engine portions of the budget. We refer to these partial plans that 
addressed the portion of the rule unaffected by the Court's remand as

[[Page 21607]]

the ``Phase I'' SIPs.\2\ Because the NOX SIP Call was 
vacated with respect to Georgia, Missouri, and Wisconsin, those States 
were not obligated to submit any SIPs by October 30, 2000. The SIPs 
that cover the portion of the rule affected by the Court decision--and 
the subject of today's action--are termed, the ``Phase II'' SIPs.
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    \2\ The Phase I emissions reductions should achieve 
approximately 90 percent of the total emissions reductions called 
for by the NOX SIP Call.
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6. What Was the Court's Order for the Compliance Date?
    In response to a motion filed by the industry/labor petitioners, on 
August 30, 2000, the DC Circuit ordered that the court order filed on 
June 22, 2000, be amended to extend the deadline for full 
implementation of the NOX SIP Call from May 1, 2003 to May 
31, 2004. This extension was calculated in the same manner used by the 
Court in extending the deadline for SIP submissions, so that sources in 
States subject to the NOX SIP Call would have 1,309 days for 
implementing the SIP as provided in the original NOX SIP 
Call.

C. What Was Contained in the Section 126 Rule?

    We have also addressed interstate NOX transport in a 
final rule (Section 126 Rule) that responds to petitions submitted by 
eight Northeast States under section 126 of the 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.
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    \3\ For Indiana, Kentucky, Michigan, and New York, only sources 
in portions of the State are affected by that rule.
    \4\ The Section 126 Rule uses the same definition of EGUs that 
we are finalizing for the NOX SIP Call in today's action.
    \5\ As discussed in the next section, on August 24, 2001, the DC 
Circuit suspended the compliance date for EGUs while we resolved a 
remanded issue related to EGU growth factors. We published our 
response to the growth factor issue on May 1, 2002 (67 FR 21868).
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    The Section 126 Rule includes a provision to coordinate the Section 
126 Rule with State actions under the NOX SIP Call. This 
provision automatically withdraws the Section 126 findings and control 
requirements for sources in a State if the State submits, and we give 
final approval to, a SIP revision meeting the full NOX SIP 
Call requirements, including the originally promulgated May 1, 2003 
compliance deadline [40 CFR 52.34(i)]. The Court changed the 
NOX SIP Call compliance deadline to May 31, 2004 after we 
had promulgated and justified the automatic withdrawal provision based 
on approval of a SIP with a May 1, 2003 compliance date (64 FR 28274-
76, May 25, 1999; 65 FR 2679-2684, January 18, 2000). As described 
below, as the result of a court decision, the Section 126 Rule was 
delayed. On April 30, 2002, we published, ``Section 126 Rule: Revised 
Deadlines; Final Rule,'' (67 FR 21522) which reset the compliance date 
and other related dates, such as the monitoring certification date. The 
new compliance date is May 31, 2004. This action harmonized the dates 
in the Section 126 Rule with those in the NOX SIP Call.
    On April 30, 2002, we published a proposal to revise the Section 
126 Rule withdrawal provision so that it would continue to function 
based on the new compliance dates and on a Phase I SIP (67 FR 21522).
1. What Was the DC Circuit Decision on the Section 126 Rule?
    On May 15, 2001, a panel of the DC Circuit largely upheld the 
Section 126 Rule in Appalachian Power v. EPA, 249 F.3d 1032 (2001). 
(Appalachian Power-Section 126). However, the Court remanded the method 
for determining growth to the year 2007 in heat input utilization by 
EGUs. This calculation is important for determining the requirements 
for EGUs. In addition, the Court vacated and remanded to us the portion 
of the rule classifying as EGUs small cogeneration units. Although in 
the Michigan decision (concerning the NOX SIP Call 
rulemaking), the DC Circuit remanded this issue on the procedural 
ground of inadequate notice, in the Appalachian Power-Section 126 
decision, the Court vacated and remanded on grounds that we did not 
justify our classification of small cogeneration units as EGUs. In an 
order dated August 24, 2001, the DC Circuit, in Appalachian Power-
Section 126 Case, remanded the Section 126 Rule with regard to the 
classification of any cogeneration units as EGUs and tolled (suspended) 
the date for EGUs to implement controls pending our resolution of the 
EGU growth factor remand.
    During the course of the litigation on the Section 126 Rule, 
individual sources or groups of sources challenged the rule on grounds 
that our allocations of allowances were improper. We resolved these 
cases with several of those sources with our agreement to propose a 
rulemaking revising the allocations.

D. What Were the Technical Amendments Rulemakings?

    When we promulgated the NOX SIP Call Rule, we decided to 
reopen public comment on the source-specific data used to establish 
each State's 2007 EGU budget (63 FR 57427, October 28, 1998). We 
extended this comment period by notice dated December 24, 1998 (63 FR 
71220). We indicated that we would entertain requests to correct the 
2007 EGU budgets to take into account errors or updates in some of the 
underlying emissions inventory and certain other specified data.
    Following our review of the comments received, we published a 
rulemaking providing Technical Amendments to, among other things, the 
2007 EGU budgets (64 FR 26298, May 14, 1999). In response to additional 
comments received, we published a second rulemaking, making additional 
Technical Amendments to the 2007 EGU budgets (65 FR 11222, March 2, 
2000). (These two rulemakings may be referred to, together, as the 
Technical Amendments Rule.) In promulgating the 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 DC Circuit Decision on the Technical Amendments?
    On June 8, 2001, the DC Circuit issued its opinion in a case 
involving the Technical Amendments. Appalachian Power v. EPA, 251 F.3d 
1026 (DC Cir. 2001). (Appalachian Power-Technical Amendments). Although 
largely upholding the Technical Amendments, the court, as in the 
Appalachian Power-Section 126 case, remanded the EGU growth factors and 
vacated and remanded the portion of the rule classifying small 
cogeneration units as EGUs. In addition, in the Appalachian

[[Page 21608]]

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 DC Circuit Remands/Vacaturs?

    In summary, the DC 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 IC 
engines;
    (2) Delayed the NOX SIP Call SIP submittal date to 
October 30, 2000. Michigan;
    (3) Delayed the date for implementation of the NOX SIP 
Call reductions to May 31, 2004. Michigan;
    (4) Remanded and vacated the inclusion of Wisconsin. Michigan;
    (5) Remanded and vacated the NOX SIP Call budgets for 
Georgia and Missouri under the 1-hour ozone NAAQS. Michigan;
    (6) Remanded and vacated the NOX SIP Call budget, as 
revised by the Technical Amendments, for Missouri, under the 1-hour and 
8-hour ozone NAAQS. Appalachian Power--Technical Amendments;
    (7) Remanded the EGU growth formula. Appalachian Power--Section 
126, Appalachian Power--Technical Amendments;
    (8) Remanded, or remanded and vacated, the classification of small 
cogeneration units as EGUs. Michigan, Appalachian Power--Section 126, 
Appalachian Power--Technical Amendments; and
    (9) Remanded the classification of any cogeneration units as EGUs. 
Appalachian Power--Section 126.

F. What Is Our Process for Addressing the Remands/Vacaturs?

    To date, we have responded to these decisions as detailed below:
    In letters dated April 11, 2000, to the Governors of the affected 
States, we advised that the States may submit by October 30, 2000 Phase 
I SIPs that include a budget allowing more emissions than under the 
NOX SIP Call Rule. This budget need not include any 
reductions from a set of EGUs that we believe includes all of the small 
cogeneration units or reductions from stationary IC engines. In 
addition, we advised Wisconsin that it need not submit a NOX 
SIP Call SIP revision. Further, we advised Georgia and Missouri that 
they did not have to submit NOX SIP Call SIPs at this time. 
We advised Alabama and Michigan that although the Court upheld the 
NOX SIP Call for their entire States, the reasoning of the 
Court's opinion concerning Georgia and Missouri supported excluding 
emissions from the coarse-grid 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.\6\ All required States have now 
submitted complete Phase I SIPs and the sanctions clocks have 
effectively been turned off.
---------------------------------------------------------------------------

    \6\ All required States have submitted final SIPs. We have 
published final approval for 16 States and the District of Columbia. 
We have published final conditional approvals for two States.
---------------------------------------------------------------------------

    On February 22, 2002, we proposed our response to the court 
decisions described above, except for the EGU growth remand. Today's 
action finalizes the second phase or Phase II of the NOX SIP 
Call by addressing the remanded and vacated issues as described above. 
In addition, we are modifying the budgets for Alabama and Michigan 
based on inclusion of only the fine grid portion of those States. 
Further, we are excluding Wisconsin from the 1-hour basis of the 
NOX SIP Call.
    Any additional emissions reductions required as a result of this 
rulemaking are reflected in the Phase II portion of the State's 
emissions budget. The emissions reductions required in Phase II are 
relatively small, representing less than 10 percent of total reductions 
required by the NOX SIP Call. Partial State budgets for 
Georgia and Missouri and the due date for the SIPs meeting the 
resulting State emissions budgets (``Phase II'' SIPs) are discussed 
below in sections II.E and II.J, respectively.
    Today's rulemaking does not address the EGU growth remand. We 
responded to that issue in an action entitled, ``Response to Court 
Remand on NOX SIP Call and Section 126 Rule,'' which was 
published in the Federal Register on May 1, 2002 (67 FR 21868). Our 
response to the growth remand was challenged in the DC Circuit. All 
parties filed briefs in May 2003 and oral argument was held on 
September 15, 2003. The Agency expects a decision by the Court in the 
January to March 2004 timeframe.
    Today's rulemaking does not address NOX SIP Call or 
Section 126 Rule issues related to the 8-hour ozone NAAQS. Although we 
stayed the findings on the NOX SIP Call based on the 8-hour 
ozone standard to address a prior remand of the standard by the DC 
Circuit (65 FR 56245, September 18, 2000), we are now evaluating 
lifting the stay in light of our recent response to the Court remand. 
In the meantime, on June 2, 2003 we published a proposed rulemaking for 
implementation of the 8-hour ozone NAAQS (68 FR 32801).

II. What Is the Scope of This Action?

    In this action, we are finalizing specific changes in response to 
the Court's rulings on the NOX SIP Call, Section 126, and 
Technical Amendments rulemakings. Specifically, we are finalizing the 
following:
    (1) Certain aspects of the definitions of EGU and non-EGU. We are 
addressing the definition of EGU as applied to cogeneration units by 
finalizing an EGU definition that excludes certain small cogeneration 
units for purposes of the NOX SIP Call and Section 126 
rulemakings. We are also finalizing a non-EGU definition that includes 
such cogeneration units. [Note that a cogeneration unit may be owned by 
a utility or a non-utility and is a unit that uses energy sequentially 
to produce both useful thermal energy (heat or steam) used for 
industrial, commercial, or heating or cooling purposes; and 
electricity.]
    (2) The control level assumed for large stationary IC engines in 
the NOX SIP Call. We proposed a range of possible control 
levels (82 percent to 91 percent) to the IC engine portion of the 
budget. We are setting the control limit for large natural gas-fired 
stationary IC engines in the NOX SIP Call at 82 percent, and 
for diesel and dual fuel stationary IC engines at 90 percent.
    (3) Partial State budgets for Georgia, Missouri, Alabama, and 
Michigan in the NOX SIP Call.
    (4) Changes to the statewide NOX budgets in the 
NOX SIP Call to reflect the appropriate increments of 
emissions reductions that States should be required to achieve with 
respect to the three remanded issues (discussed above in numbers 1, 2, 
3).
    (5) The SIP submittal dates for the required States to address the 
Phase II portion of the budget, and for Georgia and Missouri to submit 
full SIPs meeting the NOX SIP Call. We proposed a range of 
dates 6 months through 1 year from promulgation of this rule, but no 
later than April 1, 2003. Based on comments and the delay in finalizing

[[Page 21609]]

this rule, we are setting a SIP submittal date 1 year from signature of 
this rule.
    (6) The compliance date for all covered sources to meet Phase II of 
the NOX SIP Call. We proposed a compliance date of May 31, 
2004 (or, if later, the date on which the source commences operation) 
for all sources except those in Georgia and Missouri. We proposed May 
1, 2005 for sources in those States. We are setting the compliance date 
as May 1, 2007 (or, if later, the date on which the source commences 
operation) for sources States choose to control under Phase II, 
including IC engines and sources in Georgia and Missouri. Sources 
already controlled in an approved Phase I SIP are required to meet the 
compliance date stipulated in that SIP, including non-Acid Rain EGUs 
and any cogeneration units that were previously classified as EGUs and, 
whose classification changed to non-EGUs under today's rule.
    (7) The exclusion of Wisconsin from the NOX SIP Call.

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

    By way of background, in light of the Michigan decision concerning 
the NOX SIP Call, we adopted the view that the States should 
proceed with developing and submitting SIPs (termed ``Phase I'' SIPs) 
reflecting the level of required reductions that was not affected by 
the Court's ruling. Accordingly, we determined that the Phase I SIPs, 
under the Court's ruling, by October 30, 2000, should reflect all 
reductions required under the NOX SIP Call, except those 
reductions attributable to parts of the rule that the Court remanded or 
vacated, such as reductions by small cogeneration units.
    At the time, we were uncertain as to which specific units were 
small cogeneration units and what total emissions were attributable to 
small cogeneration units. Even so, we were aware that, although most of 
the EGUs that were subject to the NOX SIP Call were also 
subject to the Acid Rain Program, none of the small cogeneration units 
were subject to the Acid Rain Program. Accordingly, we erred on the 
side of caution by authorizing States, in their Phase I SIPs, to 
exclude the required reductions from all non-Acid Rain units.
    In the February 22, 2002 proposal, as applied to small cogeneration 
units, we proposed to retain the EGU definition in the Section 126 Rule 
and to retain the basic EGU definition used in the NOX SIP 
Call Rule with minor, technical revisions to make it consistent with 
the definition in the Section 126 Rule. In today's action, we are 
finalizing an EGU definition that excludes certain small cogeneration 
units. All other cogeneration units and other non-Acid Rain units are 
EGUs if the other criteria in the EGU definition are met. Further, we 
are finalizing a non-EGU definition that includes certain small 
cogeneration units. As a result, we are setting Phase II budgets that 
include reductions from small cogeneration units and non-Acid Rain 
EGUs.
    However, our review of the SIPs submitted in response to the 
NOX SIP Call indicates that the States already included the 
non-Acid Rain units in their Phase I SIPs as EGUs or non-EGUs.\7\ In 
addition, for today's final rule, with the possible exception of one 
source, we have not identified any specific small cogeneration units 
that were originally treated by EPA, and by States in their Phase I 
SIPs, as EGUs and which now are defined as non-EGUs because, in 
general, commenters did not provide specific information identifying 
any such units. The only exception involves one commenter that claimed 
that its units (located at the Tobaccoville facility) classified as 
EGUs should be classified as non-EGUs. However, the commenter did not 
provide sufficient information (e.g., information supporting the 
maximum design heat input asserted by the commenter) for us to make a 
final determination regarding the proper classification of the units. 
Therefore, today's change does not result in any change to the 
originally finalized SIP Call budgets (which included reductions from 
both Phase I and Phase II units).
---------------------------------------------------------------------------

    \7\ This is based on both a review of the applicability 
provisions in the NOX SIP Call SIPs and the budget 
demonstrations for those SIPs. For more detailed discussion, see 
section K.1 of today's preamble.
---------------------------------------------------------------------------

    Nevertheless, it is still possible that some cogeneration units 
that we classified as EGUs are small cogeneration units that should 
actually be treated as non-EGUs. To the extent any such units are 
subsequently identified to EPA, we will make any further revisions to 
the budgets of particular States during the SIP approval process. 
Similarly, we will consider, during the SIP approval process, the 
proper classification of the four units at the Tobaccoville facility 
identified by the commenter discussed above. Because we anticipate that 
few, if any, existing units treated as EGUs qualify as small 
cogeneration units, we expect few, if any, such revisions to the 
budgets will be necessary and that any such revisions that are 
necessary will be relatively small and will not affect most States.
    We are also finalizing certain technical changes to the EGU 
definition in the NOX SIP Call to make it consistent with 
aspects of the definition of EGU used in the Section 126 Rule. In 
addition, since the EGU definition establishes the dividing line 
between the EGU and non-EGU categories, the changes to the EGU 
definition result in corresponding changes to the non-EGU definition in 
the NOX SIP Call. In the process of correcting the EGU and 
non-EGU definitions, we are also finalizing some minor changes to the 
terminology, and minor corrections of awkward or inconsistent wording 
and grammatical errors in the applicability provisions.
    To begin, we provide a discussion of what preceded today's final 
decision on the treatment of cogeneration units. Under the 
NOX SIP Call, the amount of a State's significant 
contribution to nonattainment in another State included the amount of 
highly cost-effective reductions that could be achieved for large EGUs 
(i.e., EGUs serving generators with nameplate capacity exceeding 25 
MWe) and large non-EGUs (non-EGUs with maximum design heat input 
capacity exceeding 250 mmBtu/hr) in the State. No reductions for small 
EGUs or small non-EGUs were included. We determined that reductions by 
large EGUs to 0.15 lb NOX/mmBtu and by large non-EGUs to 60 
percent of uncontrolled emissions are highly cost effective. In 
developing the States' budgets, we applied definitions of EGU and non-
EGU and determined which sources were large EGUs or large non-EGUs.
    In its Michigan decision, the DC Circuit upheld this approach, but 
determined that we did not provide sufficient notice and opportunity to 
comment for one aspect of our definition of EGU and remanded the rule 
to us for further consideration. Specifically, a petitioner claimed, 
and the Court agreed, that ``EPA did not provide sufficient notice and 
opportunity for comment on [the] revision'' of the EGU definition to 
remove the exclusion, from the EGU category, of cogeneration units that 
supply one-third or less of their potential electrical output capacity, 
or 25 megawatts (MWe) or less, to any utility power distribution system 
for sale. Michigan v. EPA, 213 F.3d at 691-92. (These thresholds are 
herein referred to as the ``one-third potential electrical output 
capacity/25 MWe criteria;'' cogeneration units that meet such criteria 
are herein referred to as ``small cogeneration units.'') According to 
the Court, ``two months after the

[[Page 21610]]

promulgation of the [NOX SIP Call] rule, EPA redefined an 
EGU as a unit that serves a `large' generator (greater than 25 MWe) 
that sells electricity.'' Id. Application of the exclusion for 
cogeneration units from the definition of EGU would result in treating 
as non-EGUs those cogeneration units meeting the ``one-third potential 
electrical output capacity/25 MWe'' criteria and treating as EGUs those 
cogeneration units not meeting these criteria. See Brief of Petitioner 
Council of Industrial Boiler Owners (CIBO) at 4 (submitted in 
Michigan).
    The petitioner argued that, under the NOX SIP Call, we 
should apply these criteria for excluding cogeneration units from 
treatment as EGUs. According to the petitioner, the criteria had been 
established under the regulations implementing new source performance 
standards (NSPS) and under title IV of the CAA and the regulations 
implementing the Acid Rain Program under title IV. The petitioner also 
stated that section 112 of the CAA defines ``electricity steam 
generating unit'' to exclude cogeneration units meeting the same 
thresholds.
    The Court found that, in failing to apply the ``one-third potential 
electrical output capacity/25 MWe'' criteria for cogeneration units, 
EPA ``was departing from the definition of EGUs as used in prior 
regulatory contexts'' and ``was not explicit about the departure from 
the prior practice until two months after the rule was promulgated.'' 
Michigan, 213 F.3d at 692. Further, the Court found that:

it is an exaggeration to state that some general ``theme'' of the 
regulatory consequences of deregulation of the utility industry 
throughout rulemaking meant that EPA's last-minute revision of the 
definition of EGU should have been anticipated by industrial boilers 
as a ``logical outgrowth'' of EPA's earlier statements.

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 DC Circuit, after considering the merits of 
the issue, vacated and remanded our classification of small 
cogeneration units as EGUs.
    Appalachian Power--Section 126 and Appalachian Power--Technical 
Amendments. The Court held that we had failed to justify this 
classification and to base it on adequate record support comparing the 
NOX reduction costs of cogeneration units to those of other 
EGUs or demonstrating that there is no relevant physical or 
technological difference between small cogeneration units and other 
units treated as EGUs. The Court also remanded our classification of 
any cogeneration units as EGUs.
    In response to the Court's decisions, we addressed the cogeneration 
unit issue in the February 22, 2002 proposed rule. In the proposed 
rule, we noted that, in prior regulatory programs, we sought to 
distinguish between utilities (regulated monopolies in the business of 
producing and selling electricity) and non-utilities (e.g., independent 
power producers and industrial companies). In order to make this 
distinction, we applied the ``one third potential electrical output 
capacity/25 MWe sales'' criteria. These criteria were not always 
applied only to cogeneration units and did not uniformly result in less 
stringent regulation for units meeting the criteria. In the proposed 
rule, we stated that, with the development of competitive markets for 
electricity generation and sale, we believed that these criteria no 
longer distinguish between units in the business of producing and 
selling electricity (i.e., EGUs) and non-EGUs. In addition, we 
explained that there are no relevant differences between the way 
cogeneration units and non-cogeneration units are built and operated 
that justify continuing to use these criteria or that affect the 
general ability of cogeneration units to control NOX.
    In response to the February 22, 2002 proposed rule, most commenters 
again argued that, under the NOX SIP Call, we should apply 
the ``one third potential electrical output capacity/25 MWe sales'' 
criteria to exclude cogeneration units from treatment as EGUs. The 
comments included arguments that: Classification of small cogeneration 
units reverses EPA precedent, contradicts Congressional intent, and 
will discourage new industrial cogeneration; and it is technically and 
economically more difficult to control NOX emissions from 
non-utility units. A few commenters supported treatment of small 
cogeneration units as EGUs.
    Under today's final rulemaking, we are finalizing an EGU definition 
that excludes certain small cogeneration units and a corresponding non-
EGU definition that includes these units. We still maintain that, with 
the development of competitive markets for electricity generation and 
sale, the ``one third potential electrical output capacity/25 MWe 
sales'' criteria no longer distinguishes between units in the business 
of producing and selling electricity (i.e., EGUs) and non-EGUs. We also 
continue to believe that there are no relevant differences between the 
way cogeneration units and non-cogeneration units are built and 
operated that justify continuing to use these criteria or that affect 
the general ability of cogeneration units to control NOX. 
However, at this time, we do not believe we have adequate record 
information comparing the NOX reduction costs of all types 
of industrial cogeneration units to those of other units that are 
treated as EGUs.
    Our discussion below begins with some background on the historical 
definition of utility unit and the definition of EGU in the 
NOX SIP Call and the Section 126 rulemaking. We then discuss 
today's final rule, including our final decision on the treatment of 
cogeneration units and the specific revisions to the definition of EGU 
and corresponding revisions to the definition of non-EGU.
1. What Is the Historical Definition of Utility Unit?
    As discussed in the February 22, 2002 proposed rule (67 FR 8402-3), 
in prior regulatory programs, we have used variations of the ``one-
third potential electrical output capacity/25 MWe sales'' criteria to 
distinguish between utilities and non-utilities. The Agency began using 
these criteria in 1978, in 40 CFR part 60, subpart Da. Subpart Da 
established NSPS for ``electric utility steam generating units'' 
capable of combusting more than 250 mmBtu/hr of fossil fuel. ``Electric 
utility steam generating unit'' was defined as a unit ``constructed for 
the purpose of supplying more than one-third of its potential electric 
output capacity and more than 25 MWe electrical output to any utility 
power distribution system for sale'' (40 CFR 60.41a). In that case, the 
criteria were not used to exempt units entirely from NSPS. Rather, the 
criteria were used to classify units capable of combusting more than 
250 mmBtu/hr of fossil fuel as either ``electric utility steam 
generating units'' subject to the requirements under subpart Da or to 
classify them as non-utility ``steam generating units'' that, depending 
on the date of construction, continued to be subject to the 
requirements for ``Fossil-Fuel-Fired Steam Generators'' under subpart D 
or subsequently became subject 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''), Sec.  60.40b(a) (stating that subpart 
Db applies to ``steam generating units'' with heat input capacity of 
more than 100 mmBtu/hr), and Sec.  60.40b(e) (stating that ``electric 
steam generating units'' subject to subpart Da are not subject to 
subpart

[[Page 21611]]

Db). Depending on the specific circumstances (e.g., type of equipment 
and fuel) of the unit involved, some of the emission limits in subpart 
Db may be the same as or more stringent than those in subpart D or Da.
    We explained that we were distinguishing, in subpart Da, between 
``electric utility steam generating units'' and ``industrial boilers'' 
because ``there are significant differences between the economic 
structure of utilities and the industrial sector'' (44 FR 33580, 33589, 
June 11, 1979). The ``one-third potential electrical output capacity/25 
MWe sales'' criteria were used as a proxy for utility vs. industrial/
commercial/institutional (i.e., non-utility) ownership of the units; 
utility-owned units were covered by subpart Da, while non-utility-owned 
units were covered by subpart D or Db.
    A similar type of distinction between utility and non-utility units 
(using the ``one-third potential electrical output capacity/25 MWe 
sales'' criteria) continued under the CAA Amendments of 1990, in both 
title IV and section 112 of title I, but was applied only to 
cogeneration units. Title IV established the Acid Rain Program whose 
requirements apply to ``utility units.'' Section 402(17)(C) excludes a 
cogeneration unit from the definition of ``utility unit'' unless the 
unit ``is constructed for the purpose of supplying, or commences 
construction after the date of enactment of [title IV] and supplies, 
more than one-third of its potential electric output capacity and more 
than 25 MWe electrical output to any utility power distribution system 
for sale.'' 42 U.S.C. 7651a(17)(C). See also 40 CFR 72.6(b)(4). Section 
112 of the CAA, which addresses hazardous air pollutants, excludes from 
the definition of ``electric utility steam generating unit'' 
cogeneration units (but not non-cogeneration units) that meet the 
``one-third potential electrical output capacity/25 MWe sales'' 
criteria [42 U.S.C. 7412(a)(8)]. Under section 112, emission limits 
established by the Administrator for the pollutants listed in section 
112(b) apply generally to stationary sources but apply to ``electric 
utility steam generating units'' only if the Administrator makes a 
specific finding. The Administrator must conduct a study of the 
``hazards to public health reasonably anticipated to occur'' from 
emissions from such units and determine if regulation of ``electric 
utility steam generating units'' is ``appropriate and necessary.'' 42 
U.S.C. 7412(n)(1)(A). In summary, the above-described provisions vary 
as to both: (1) The application of the ``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 stringent regulation under some 
provisions and less stringent or later regulation under other 
provisions.
2. What Was the NOX SIP Call Definition of EGU?
    In the NOX SIP Call rulemaking, we continued the general 
approach, described above, of distinguishing between units in the 
electric generation business (here, EGUs) and units in the industrial 
sector (here, non-EGUs). However, we adopted a different method of 
defining which units are in the electric generation business by 
changing the definition of EGU. We defined EGU by applying to all 
fossil fuel-fired units the methodology described in detail below and 
did not apply to cogeneration units the ``one-third potential 
electrical output/25 MWe sales'' criteria. Under the methodology 
applied to all units, after determining the date on which a unit 
commenced operation (i.e., commenced combusting fuel), we determined 
whether the unit should be classified as an EGU or a non-EGU by 
applying the appropriate criteria depending on the commencement of 
operation date. Then we classified the unit as a large or small EGU or 
a large or small non-EGU.
    Specifically, we noted in a December 24, 1998 supplemental action 
that the NOX SIP Call used the following methodology for 
classifying all units (including cogeneration units) in the States 
subject to the NOX SIP Call as EGUs or non-EGUs (63 FR 
71220, 71223). We applied this methodology to cogeneration units and 
not the ``one-third potential electrical output capacity/25 MWe sales'' 
criteria. Id.

    (a)(i) For units commencing operation before January 1, 1996, we 
classified as an EGU any unit serving a generator producing any 
electricity for sale under firm contract to the electric grid. In 
the December 24, 1998 supplemental action, we did not define the 
term ``electricity for sale under firm contract to the electric 
grid.'' \8\
---------------------------------------------------------------------------

    \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). In the February 22, 2002 proposed rule, we proposed to 
adopt the definition for the term provided in the January 18, 2000 
Section 126 final rule. This definition was based on language from 
the Glossary of Electric Utility Terms, Edison Electric Institute, 
Publication No. 70-40 (definition of ``firm'' power). Generally, 
capacity ``under firm contract to the electricity grid'' is included 
on Energy Information Administration (EIA) form 860A (called EIA 
form 860 before 1998) or is reported as capacity projected for 
summer or winter peak periods on EIA form 411 (Item 2.1 or 2.2, line 
10).
---------------------------------------------------------------------------

    (ii) For units commencing operation before January 1, 1996, we 
classified as a non-EGU any unit not serving a generator producing 
electricity for sale under firm contract to the grid.
    (iii) For units commencing operation on or after January 1, 
1996, we classified as an EGU any unit serving a generator producing 
any amount of electricity for sale, except as provided in paragraph 
(a)(iv) below.
    (iv) For units commencing operation on or after January 1, 1996, 
we classified as non-EGUs the following: any unit not serving a 
generator producing electricity for sale; or any unit serving a 
generator with a nameplate capacity equal to or less than 25 MWe, 
producing electricity for sale, and with the potential to use 50 
percent or less of the usable energy of the unit. In the December 
24, 1998 supplemental action, we did not define the term ``usable 
energy.'' \9\ (b)(i) For a unit classified as an EGU under paragraph 
(a)(i) or (a)(iii) above, we then classified it as a small or large 
EGU. An EGU serving a generator with a nameplate capacity greater 
than 25 MWe is a large EGU. An EGU serving a generator with a 
nameplate capacity equal to or less than 25 MWe is a small EGU. In 
the December 24, 1998 supplemental action, we did not expressly 
define the term ``nameplate capacity.'' \10\
---------------------------------------------------------------------------

    \9\ For purposes of the January 18, 2000 Section 126 final rule, 
we used the more familiar term ``potential electrical output 
capacity,'' rather than the term ``usable energy.'' We defined 
``potential electrical output'' using the longstanding definition of 
the latter term as ``33 percent of a unit's maximum design heat 
input'' (65 FR 2694 and 2731). In the February 22, 2002 proposed 
rule, we proposed to adopt the same term and definition used in the 
January 18, 2000 Section 126 final rule. ``Potential electrical 
output capacity'' is used, and defined in this way, in part 72 of 
the Acid Rain Program regulations (40 CFR 72.2 and 40 CFR part 72, 
appendix D) and in the new source performance standards (40 CFR 
60.41a).
    \10\ In the part 96 model rule in the NOX SIP Call 
(63 FR 57356, 57514-38, October 27, 1998), and subsequently for 
purposes of the January 18, 2000 Section 126 final rule (65 FR 2729 
and 2731), we adopted the long-standing definition of ``nameplate 
capacity'' as ``the maximum electrical generating output (in MWe) 
that a generator can sustain over a specified period of time when 
not restricted by seasonal or other deratings as measured in 
accordance with the United States Department of Energy standards.'' 
In the February 22, 2002 proposed rule, we proposed to adopt the 
same definition used in the January 18, 2000 Section 126 final rule. 
The term is defined in this way in part 72 of the Acid Rain Program 
regulations (40 CFR 72.2).
---------------------------------------------------------------------------

    (ii) For a unit classified as a non-EGU under paragraph (a)(ii) 
or (a)(iv) above, we then classified it as a small or large non-EGU. 
A non-EGU with a maximum design heat input greater than 250 mmBtu/
hour is a large non-EGU. A non-EGU with a maximum design heat input 
equal to or less than 250 mmBtu/hour is a small non-EGU. But see 63 
FR 71224 (explaining procedures used if data on boiler heat input 
capacity were not available). In the December 24, 1998 supplemental 
action, we did not expressly

[[Page 21612]]

define the term ``maximum design heat input.'' \11\ The term is 
analogous to the term ``nameplate capacity'' in that it uses the 
manufacturer's specifications to categorize the size of the 
equipment (the generator, in the case of an EGU or the boiler or 
turbine or combined-cycle system, in the case of non-EGU).\12\
---------------------------------------------------------------------------

    \11\ In the part 96 model rule in the NOX SIP Call 
(63 FR 57516) and subsequently for purposes of the January 18, 2000 
Section 126 final rule (65 FR 2729), we defined ``maximum design 
heat input'' as ``the ability of a unit to combust a stated maximum 
amount of fuel per hour (in mmBtu/hr) on a steady state basis, as 
determined by the physical design and physical characteristics of 
the unit.'' In the February 22, 2002 proposed rule, we proposed to 
adopt the same definition used in the January 18, 2000 Section 126 
final rule.
    \12\ For example, in establishing the State budgets for large 
EGUs and large non-EGUs, we identified existing units as being large 
or small based on nameplate capacity (for EGUs) or maximum design 
heat input (for non-EGUs), determined each unit's baseline heat 
input (using 1995 or 1996) and, after calculating total heat input 
for large EGUs and for large non-EGUs, grew the total amounts out to 
2007 using heat input growth rates to account for new units and 
increased utilization. There was no provision for modifying the 
budgets to remove a unit initially qualifying as a large EGU or 
large non-EGU if the unit changed its generating or heat input 
capacity.
---------------------------------------------------------------------------

    As stated previously, we defined the term ``EGU'' by applying to 
all units, including cogeneration units, the methodology in paragraphs 
(a)(i) and (a)(iii) above and used the methodology in paragraphs 
(a)(ii) and (a)(iv) above to define units as non-EGUs. We did not use, 
for cogeneration units, the ``one-third potential electrical output 
capacity/25 MWe sales'' criteria in the cogeneration exclusion. It was 
the fact that we did not apply these criteria to cogeneration units 
that petitioners challenged in Michigan. As discussed further below, we 
are adopting essentially these criteria in today's final rule.
3. What Is the Rationale for the Final Rule's Treatment of Cogeneration 
Units?
    a. Distinction between units in the electric generation business 
and units in the industrial sector. Distinguishing between units 
producing electricity for sale and units producing electricity for 
internal use or producing steam is a long-standing approach in setting 
emission limits. In the NOX SIP Call, the Section 126 Rule, 
and today's final rule, we continue to take this general approach by 
setting different emission limits for units producing electricity for 
sale (EGUs) and units that do not produce electricity for sale (non-
EGUs).
    We are retaining this general approach for several reasons. First, 
this is a long-standing approach, and few, if any, commenters in the 
NOX SIP Call and Section 126 rulemakings supported 
abandoning the distinction between units in the electric generation 
business and units in the industrial sector. Second, after organizing 
the units into these two categories, we found that there was some 
difference in the average compliance costs of the two groups. See 65 FR 
2677, January 18, 2000 (estimating average large EGU control costs as 
$1,432 per ton in 1990 dollars in 1997 and average large non-EGU costs 
as $1,589 per ton). Third, this approach tends to result in units that 
directly compete in the electric generation business having to meet the 
same emission limit, and that result seems reasonable.
    In the May 15, 2001 decision in the Section 126 case, the DC 
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. We note that this 
issue is not unique to cogeneration units and is inherent in any 
regulatory program that distinguishes between units in the electric 
generation business and units that are in the industrial sector and 
sets different emission limits for the two groups.\13\ As previously 
discussed, we are continuing to use the general approach of 
distinguishing between units in the electric generation business and 
units in the industrial sector in the NOX SIP Call and 
Section 126 Rule. We recognize that this may result in units that are 
physically identical being regulated differently based on whether or 
not electricity--particularly electricity for sale--is produced by the 
unit. However, before abandoning the 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--we believe that it is prudent to gain experience in 
operating the trading program under the NOX SIP Call and 
Section 126 Rule. We note that we have already begun the process of 
treating these units similarly because EGUs and non-EGUs will 
participate in one trading program and will trade the same 
NOX allowances. After we have gained experience with the 
NOX SIP Call and Section 126 trading program, we intend to 
consider whether to treat as the same all large boilers, whether they 
produce electricity or not.
---------------------------------------------------------------------------

    \13\ In fact, use of the ``one-third potential electrical output 
capacity/25 MWe sales'' criteria for cogeneration units 
distinguishes between EGU cogeneration units and non-EGU 
cogeneration units based on the cogenerator's amount of electricity 
sales and raises the same issue. Under these criteria, two 
physically identical cogeneration units could have different 
emission limits simply because one produces and sells the requisite 
amount of electricity and the other produces more electricity for 
internal use and does not sell the requisite amount.
---------------------------------------------------------------------------

    b. Effect of electricity competition and electric power 
restructuring on distinction between utilities and non-utilities. As 
discussed in the February 22, 2002 proposed rule (see 67 FR 8405-06), 
the increasingly competitive nature of the electric power industry and 
the significant and increasing participation of non-utilities (e.g., an 
independent power producer or an industrial company) in competitive 
electricity markets support similar treatment of utilities and non-
utilities. In the proposed rule, we stated that, with these changes in 
the electric power industry and electricity markets, there is no longer 
a factual basis for excluding cogeneration units from treatment as EGUs 
by using the ``one-third potential electrical output capacity/25 MWe 
sales'' criteria.
    Many industry commenters argued that EGU should be defined to 
exclude a cogeneration unit meeting the ``one-third potential 
electrical output capacity/25 MWe sales'' criteria. They raised several 
issues in support of their argument of not including small cogeneration 
units in the definition of EGU. First, commenters argued that the 
classification of cogeneration units as EGUs reversed our precedent in 
previous regulations and contradicts Congressional intent underlying 
the CAA. They also argued that new industrial cogeneration, and the 
potential emissions and energy efficiency benefits that could result, 
would be discouraged. In addition, commenters maintained that the costs 
of any NOX controls for these units would be reflected in 
the market for the products produced by the industrial company that 
uses energy from the cogeneration unit and not in the electricity 
market. Commenters maintained that a manufacturing company can engage 
in sales of electricity without being in the business of selling 
electricity. Sometimes such a company exports electricity to the local 
utility, even though it remains a net importer of electricity over the 
long-term. Furthermore, commenters argued that we justified our 
definition on deregulation and have failed to consider the halt on 
deregulation efforts that California's electricity crisis spurred in 
other States.
    c. Differences between the design and operation of cogeneration 
units and

[[Page 21613]]

non-cogeneration units. In the February 22, 2002 proposed rule, we 
stated that there appear to be no physical, operational, or 
technological differences between cogeneration units producing 
electricity for sale and non-cogeneration units producing electricity 
for sale that would prevent cogeneration units classified as EGUs from 
achieving average NOX reductions, and incurring average 
reduction costs, similar to those achieved by non-cogeneration units. 
We concluded in the proposed rule that there appear to be no such 
differences that would justify using the ``one-third potential 
electrical output capacity/25 MWe sales'' criteria for classifying 
cogeneration units as EGUs or non-EGUs, rather than the classification 
methodology used for all other units. We still believe that there are 
no relevant differences between the way cogeneration units and non-
cogeneration units are built and operated that affect the general 
ability of cogeneration units to control NOX. However, at 
this time, we do not believe we have adequate record support comparing 
the NOX reduction costs of all types of industrial 
cogeneration units to those of other units that are treated as EGUs.
    As discussed in the February 22, 2002 proposed rule, cogeneration 
units under the NOX SIP Call or the Section 126 Rule operate 
in two basic configurations.\14\ The first is a boiler followed by a 
steam turbine-generator. In this configuration, steam is generated by a 
boiler. The steam is first used to power a steam turbine-generator, 
while the remaining steam is used for an industrial application or for 
heating and cooling. The boiler that generates the steam used in this 
manner is designed and operated in essentially the same way as a boiler 
that generates steam used only to power a steam turbine-generator. 
Therefore, any controls 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.
---------------------------------------------------------------------------

    \14\ These two configurations are for cogeneration units in 
topping cycle cogeneration facilities, where energy is used 
sequentially, first to produce electricity and then to produce 
thermal energy for process use or heating and cooling. In bottoming 
cycle cogeneration facilities, energy is used sequentially first to 
produce thermal energy and then to produce electricity. (See 
Cogeneration Applications Considerations, R.W. Fisk and R.L. 
VanHousen, GE Power Systems, 1996, Docket No. OAR-2001-0008, Item 
No. XII-L-04 at 1-2.) The cogeneration units subject to the 
NOX SIP Call and the Section 126 Rule are boilers, 
turbines, or combined cycle systems and so are likely to operate in 
topping cycle cogeneration facilities.
---------------------------------------------------------------------------

    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 are designed and 
operated in essentially the same way as combined cycle units that 
generate only electricity. The waste heat from the gas turbine serves 
as the heat input (possibly supplemented by a duct burner) to the heat 
recovery steam generator that is used to power the steam turbine. Both 
the gas turbine and the steam turbine are connected to generators to 
produce electricity. The gas turbine generator and the heat recovery 
steam generator portions can be adapted to supply process steam as well 
as electricity. These units typically emit at NOX levels 
well below 0.15 lbs/mmBtu even without the use of post-combustion 
controls. Furthermore, selective catalytic reduction (SCR) has been 
used extensively on combined cycle units that are used for cogeneration 
and those used for generation of electricity only and results in 
NOX emissions at levels well below 0.15 lb/mmBtu. (See GE 
Combined-Cycle Product Line and Performance, GE Power Systems, October 
2000, Docket No. OAR-2001-0008, Item No. XII-L-04 at 10-11.)
    Both cogeneration configurations identified above are used at 
utility and non-utility facilities that produce electricity for sale. 
The steam generated at these facilities is divided between powering a 
steam turbine and serving process uses or heating and cooling. The 
cogeneration units with the same configuration at these facilities are 
almost identical in design, except that a non-utility facility may use 
more of the steam for process uses or heating and cooling and less for 
electricity generation.
    Further, in comparison to a non-cogeneration system that generates 
electricity for sale, either type of cogeneration system looks 
essentially the same as such a non-cogeneration system except for the 
addition of valves and piping to send the steam for process use or 
heating and cooling. In both the cogeneration and non-cogeneration 
systems that generate electricity for sale, all the flue gas 
(containing the NOX emissions) exiting the combustion 
process can be directed through the pollution control devices and then 
through a stack. Because the cogeneration and non-cogeneration systems 
are of essentially the same design and the flue gas exits the systems 
in the same manner, the control of NOX emissions can be 
achieved in the same manner. Any post-combustion pollution control 
device used for NOX control in either system is located in 
the same place and operated in the same manner.\15\ As discussed in the 
February 22, 2002 proposed rule and the technical support document,\16\ 
post-combustion NOX control technologies, i.e., selective 
non-catalytic reduction (SNCR) and SCR, are available for use on both 
non-cogeneration and cogeneration units producing electricity for sale. 
The technical support document and the other documents cited in the 
proposed rule support the following conclusions:
---------------------------------------------------------------------------

    \15\ For examples and discussion of how post-combustion controls 
apply to cogeneration units, see Docket No. OAR-2001-0008 (Legacy 
Docket No. A-96-56), Item Nos. XII-L-02; XII-L-03; and XII-L-05 at 
10-11 and 13 (Figure 15). In fact, this is also true for boilers 
that do not serve any generator. Boilers with or without a generator 
and with or without the capability to cogenerate are of essentially 
the same design, and the flue gas exits the systems in the same 
manner. Any post-combustion pollution control device used for 
NOX control in either system is located in the same place 
and operated in the same manner.
    \16\ ``Lack of Relevant Physical or Technological Differences 
Between Cogeneration Units and Utility Electricity Generating 
Units,'' September 25, 2000, Docket No. OAR-2001-0008, Item No. XII-
K-47.
---------------------------------------------------------------------------

    (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 has been used at a wide range of temperatures 
(e.g., from 1250 degrees F to 2600 degrees F) and has been designed to 
handle a wide range of load variation (e.g., 33 percent to 100 percent 
of a unit's maximum continuous rating).
    (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. The SCR has been demonstrated on a 
wide range of boiler types and sizes and on combined cycle systems. The 
SCR has been used at a wide range of temperatures (e.g., 450 degrees F 
to 1100 degrees F) and

[[Page 21614]]

has been designed to handle a wide range of load variation.
    In the February 22, 2002 proposed rulemaking, we requested comment 
on, and specific information supporting or contradicting, our 
conclusions that there are no relevant physical, operational, or 
technological differences and no significant difference in average 
control retrofit cost for cogeneration versus non-cogeneration units 
producing electricity for sale. In response to the proposed rule, 
commenters raised concerns that it is technically and economically more 
difficult to control NOX in industrial cogeneration units 
than in non-utility units because they are smaller sized than utility 
boilers, fire multiple fuels and often co-fire two or more fuels, 
operate in a load-following mode, have lower annual operating load or 
capacity factor, and have boiler temperature profiles and other factors 
that affect pollution control devices. A few commenters supplied data 
or indicated the cost of control for certain units. One commenter 
stated that reasonably available control technology (RACT) analysis for 
an unidentified, 350 million British thermal units (mmBtus)/hr coal-
fired stoker boiler indicated that the only technically feasible 
NOX control identified by boiler and NOX control 
experts was conversion to fluidized bed combustion at a cost of over 
$11,000/ton based on year-round operation and over $26,000/ton 
considering only the ozone season. Another commenter cited EPA's 
``Alternative Control Techniques Document: NOX Emissions 
from Industrial/Commercial/Institutional Boilers' (March 1994) (1994 
ACT), indicating cost effectiveness of SCR for a 400 mmBtu/hr 
pulverized coal boiler of $3,400-$4,200/ton and cost effectiveness of 
SNCR for a 470 mmBtu pulverized coal boiler (with low NOX 
burners and a 50 percent load factor) of more than $1,800/ton. An 
additional commenter indicated costs in excess of $2,500 per seasonal 
ton at the Tobaccoville facility (in 1990 dollars).
    In light of the limited control cost data provided by commenters, 
we conclude that at this time we lack sufficient cost data to show 
whether there is a significant difference in the average cost of 
controlling NOX emissions from cogeneration units, as 
compared to non-cogeneration units. The 1994 ACT costs cited by one 
commenter are not relevant because the boilers involved were not 
cogeneration units. In addition, the cited costs were early estimates 
by the Agency on the cost of SCR and SNCR and have been superceded by 
later data and documents. Further, the commenters' indicated that costs 
at the coal-fired stoker and at the Tobaccoville facility do not 
necessarily support the claim that average costs of controlling 
NOX at cogeneration units are higher than such costs at non-
cogeneration units. Due to economies of scale, smaller units, like some 
industrial cogeneration units and smaller utility units, may have costs 
that are higher than the average costs. We acknowledge that the actual 
cost impacts will vary from unit to unit, with the costs being lower 
for some and higher for others. In our analysis, we presented average 
costs of control and understood that some units may have higher costs 
than the average. We note that units may participate in a trading 
program that allows for the buying of allowances for units that have 
more difficulty controlling NOX emissions.
    Furthermore, we note that we have cost information on one other 
cogeneration unit. In our cost analysis of EGUs, we used an average 
capital cost of $69.70 to $71.80 per kilowatt for SCR on a 200 MWe 
coal-fired EGU. See ``Analyzing Electric Power Generation Under the 
CAAA,'' U.S. EPA, March 1998, Docket No. OAR-2001-0008, Item No. V-C-03 
at A5-7 (Table A5-5). The record shows a capital cost of $58 per 
kilowatt for SCR on a new coal-fired cogeneration unit. See ``Status 
Report on NOX Control Technologies and Cost Effectiveness 
for Utility Boilers,'' Northeast States for Coordinated Air Use 
Management and Mid-Atlantic Regional Air Management Association, June 
1998, Docket No. OAR-2001-0008, Item No. VI-B-05 at 151-53. We maintain 
that this cost is reasonably consistent with the average cost that we 
determined for all EGUs.\17\ However, as commenters noted, industrial 
cogeneration units cover a wide range of firing types and fire a wide 
range of fuels. Since the cogeneration unit used as part of the basis 
for the control costs for EGUs was a medium-size, pulverized coal plant 
very similar to many coal-fired utility boilers, it is not necessarily 
representative of other types of boilers used for industrial 
cogeneration units such as stoker boilers firing a combination of 
fuels. Since we have limited control cost data for such other types of 
industrial cogeneration units, we believe that we do not have a 
sufficient record at this time to show whether there is a significant 
difference in the average cost of controlling NOX emissions 
from these units.
---------------------------------------------------------------------------

    \17\ We also note that the dollar per ton cost for this 
installation is $2,800 to $3,000 per ton of NOX removed. 
This is higher than the average cost for EGUs because the unit 
started at a low NOX rate (0.16 lb/mmBtu) and controls 
down to 0.07-0.08 lb/mmBtu, not because the unit is a cogenerator. 
If the unit only generated electricity and had the same starting 
NOX rate, the cost would be the same.
---------------------------------------------------------------------------

4. What Revisions Are Being Made to the Definition of EGU in the 
NOX SIP Call and the Section 126 Rule?
    In today's final rule, we are addressing three aspects of the EGU 
definition. First, for purposes of the NOX SIP Call and the 
Section 126 Rule and in a change from the February 22, 2002 proposed 
rule (see 67 FR 8401-8410), we are finalizing an EGU definition that 
applies to cogeneration units the ``one-third potential electrical 
output/25 MWe sales'' criteria in classifying the units as EGUs or non-
EGUs. For all other units, we are continuing to apply the basic 
approach used in the NOX SIP Call Rule, described in the 
December 24, 1998 supplemental action (63 FR 71233), and the approach 
in the Section 126 Rule for such classification. Second, we are 
finalizing some minor changes to the categorization (based on dates of 
commencement of operation) of units under the NOX SIP Call 
definition of EGU (set forth in section II.A.2 above) for purposes of 
applying the firm-contract criterion used to classify units as EGUs. 
While the NOX SIP Call categorizes units as those commencing 
operation before January 1, 1996 and those commencing operation on or 
after January 1, 1996, today's final rule categorizes units as those 
commencing operation before January 1, 1997, those commencing operation 
in 1997 or 1998, and those commencing operation on or after January 1, 
1999. These new categories based on commencement of unit operation are 
the same as the categories adopted in the January 18, 2000 Section 126 
final rule, under which units commencing operation before 1999 and 
generating electricity for sale, but not for sale under a firm contract 
to the grid (i.e., not under a guaranteed commitment to provide the 
electricity), were classified as non-EGUs and units commencing 
operation in 1999 or thereafter and generating any electricity for sale 
were generally classified as EGUs. Today's final rule uses this same 
approach to classify units as EGUs or non-EGUs, except for the 
application to cogeneration units of the ``one-third potential 
electrical output/25 MWe sales'' criteria. Third, we are also 
finalizing some minor changes to the terminology, and minor corrections 
of awkward or inconsistent wording and grammatical errors in the 
applicability provisions. For example, we are adopting the term 
``potential electrical output capacity'' and the definitions of the 
terms ``electricity for sale under firm contract to the electric 
grid,'' ``potential

[[Page 21615]]

electrical output capacity,'' ``nameplate capacity,'' and ``maximum 
design heat input'' used in the January 18, 2000 Section 126 Rule.
    a. Application of the ``one-third potential electrical output/25 
MWe sales'' criteria, in lieu of the firm-contract criterion, to 
cogeneration units. As explained in the NOX SIP Call Rule, 
described in the December 24, 1998 supplemental action (63 FR 71233), 
and the Section 126 Rule, we adopted the approach of using the firm-
contract criterion for units (non-cogeneration and cogeneration units) 
that commenced operation before 1999. We stated that the criterion 
provides a reasonable transitional means of making the EGU/non-EGU 
classification since, for units commencing operation in 1999 or 
thereafter, a unit that generates any electricity for sale is 
classified as an EGU. We explained that the firm-contract criterion 
provides a reasonable way of identifying which cogeneration units have 
been significantly enough involved in the business of generating 
electricity for sale that their owners have provided guaranteed 
commitments to provide electricity from the units to one or more 
customers. We also stated that the historical information necessary to 
apply the firm-contract criterion to cogeneration units (and other 
units) is already available to us. Capacity involved in sales of 
electricity ``under firm contract to the electricity grid'' has been 
generally included on EIA form 860A (called EIA form 860 before 1998) 
or reported to EIA as capacity projected for summer or winter peak 
periods on EIA form 411 (Item 2.1 or 2.2, line 10). The historical 
information from these forms is publicly available.
    Nevertheless, in today's final rule, we are adopting the ``one-
third potential electrical output/25MWe sales'' criteria for 
classifying cogeneration units as EGUs or non-EGUs. The reasons for 
this approach are discussed below in II.A.4. Regardless of when a 
cogeneration unit commenced or commences operation, a cogeneration unit 
supplying more than one-third of its potential electrical output and 
more than 25 MWe to a utility power distribution system for sale during 
any year in the relevant period is classified as an EGU, and a 
cogeneration unit that does not meet these criteria is classified as a 
non-EGU. As stated above, criteria are used in order to determine 
whether a cogeneration unit is exempt from the Acid Rain Program under 
section 402(17)(C) of the CAA, as implemented under Sec.  72.4(b)(4) of 
the Acid Rain regulations. See 40 CFR 72.4(b)(4); and 58 FR 15634, 
15636-38 (1993). Consequently, in implementing the use of the ``one-
third'' potential electrical output/25 MWe sales'' criteria for 
classifying cogeneration units in the NOX SIP Call and in 
the Section 126 Rule, today's final rule references Sec.  72.4(b)(4). 
Thus, in general, a cogeneration unit that meets the criteria for an 
unaffected unit in the Acid Rain Program under Sec.  72.4(b)(4) for the 
relevant time period is defined as a non-EGU, while a cogeneration unit 
that fails to meet the criteria for such exemption for the relevant 
time period is defined as an EGU. Moreover, for cogeneration units 
commencing operation before January 1, 1997, the relevant period is 
1995-1996; for cogeneration units commencing operation during 1997-1998 
the relevant period is 1997-1998; and for units commencing operation on 
or after January 1, 1999, the relevant period is 1999 and thereafter. 
These same periods or categories are used in classifying non-
cogeneration units as EGUs or non EGUs. We are adopting the categories 
so that a consistent set of categories applies to all units (either 
cogeneration or non-cogeneration units), which will simplify and 
facilitate the categorization of units by EPA, States, and others.\18\ 
As discussed below, we are continuing to apply the firm-contract 
criterion (for units commencing operation before 1999) or the 
electricity sales criterion (for units commencing operation in or after 
1999) for classifying non-cogeneration units as EGUs or non-EGUs.
---------------------------------------------------------------------------

    \18\ While we wish to be as consistent as possible in the 
definitions used in the NOX SIP Call and the definitions 
used in the Section 126 Rule, there is an important difference in 
the reason for categorizing units in the two rulemakings. In the 
NOX SIP Call, the definitions are used to set the State 
budgets and therefore need to focus on 1995 and 1996, the base years 
used for developing budgets. State-specific growth rates were used 
to take into account units commencing operation after the base 
years. The NOX SIP Call model rule (in part 96) did not 
use these definitions in the applicability and allowance allocation 
provisions, and States adopted their own applicability and allowance 
allocation provisions in their SIPs. Thus, the portion of the 
definitions that affects the NOX SIP Call is the portion 
pertaining to units in operation before January 1, 1997. In the 
Section 126 Rule, the definitions are used for purposes of 
determining applicability and allocating allowances. Thus, in the 
Section 126 Rule, the definitions must address units commencing 
operation after 1996, as well as those operating in 1995 and 1996.
---------------------------------------------------------------------------

    b. Application of the firm-contract criterion to non-cogeneration 
units. As noted above, in the NOX SIP Call Rule [as 
described in the December 24, 1998 supplemental action (63 FR 71233)] 
and the Section 126 Rule, we adopted the approach of using the firm-
contract criterion for non-cogeneration units (as well as for 
cogeneration units) that commenced operation before 1999. In the 
February 22, 2002 proposed rule, we did not reconsider that general 
approach for non-cogeneration units, but only for cogeneration units. 
However, we did propose minor changes in the categorization of non-
cogeneration units based on their date of commencement of operation. We 
proposed to adopt commencement of operation before 1999 or on or after 
January 1, 1999 as the dividing line between units to which the firm-
contract criterion are applied and those to which the electricity sales 
criterion are applied. Further, for application of the firm-contract 
criterion, we proposed to distinguish between units commencing 
operation before 1997 and those commencing operation in 1997 or 1998. 
Some commenters on the proposed rule argued for the keeping of the 
``firm contract'' language for units commencing operation in 1999 or 
later, especially if we would continue with our proposed definition of 
EGUs with regard to cogeneration units.
    In today's final rule, we are finalizing, for non-cogeneration 
units, the categorization of units under the NOX SIP Call as 
those units commencing operation before January 1, 1997, those 
commencing operation in 1997 or 1998, and those commencing operation on 
or after January 1, 1999.
    The firm-contract criterion is not applied to non-cogeneration 
units commencing operation on or after January 1, 1999. The 
classification of units commencing operation on or after January 1, 
1999 will be based on whether the unit produces any electricity for 
sale. In general, any non-cogeneration unit that produces electricity 
for sale will be an EGU, except that the non-EGU classification will 
apply to a unit serving a generator that has a nameplate capacity equal 
to or less than 25 MWe, from which any electricity is sold, and that 
has the potential (determined based on nameplate capacity) to use 50 
percent or less of the potential electrical output capacity of the 
unit.
    As discussed in the February 22, 2002 proposed rule, for several 
reasons, we are establishing January 1, 1999 as the cutoff date for 
applying EGU and non-EGU definitions based on electricity sales under 
firm contract to the grid and the start date for applying EGU and non-
EGU definitions based on electricity sales. First, information is 
available to us on electricity sales on a calendar year basis only. 
Consequently, the classification of units based on whether the 
generators that they serve are involved in firm-contract electricity 
sales must be made on a calendar year basis, and any cutoff must start 
on January 1. Second, use of the January 1,

[[Page 21616]]

1999 cutoff date for the NOX SIP Call is consistent with the 
use of that same cutoff date in the Section 126 Rule. Third, the 
January 1, 1999 cutoff date will limit the ability of owners or 
operators of new units that might otherwise qualify as large non-EGUs 
from obtaining small EGU classification for the units and thereby 
avoiding all emission reduction requirements. For example, since the 
cutoff date and the relevant period for determining electricity sales 
are past, the owner of a large new unit that would otherwise not serve 
a generator will not be able to obtain small EGU classification simply 
by adding a very small generator (e.g., 1 MWe) to the unit and selling 
a small amount of electricity under firm contract to the grid.
    c. Application of Section 126 terms and definitions and correction 
of awkward or inconsistent wording and grammatical errors. We also are 
finalizing for use in the NOX SIP Call the same term 
``potential electrical output capacity,'' and the same definitions of 
the terms ``electricity for sale under firm contract to the electric 
grid,'' ``potential electrical output capacity,'' ``nameplate 
capacity,'' and ``maximum design heat input,'' adopted in the January 
18, 2000 Section 126 final rule and used in the EGU definition in the 
regulations (i.e., part 97) implementing the Section 126 program. The 
basis for these terms and definitions is set forth above.
    In addition, we are correcting some awkward or inconsistent wording 
and grammatical errors without making any substantive change in the EGU 
and non-EGU definitions. For example, instead of referring to units 
commencing operation ``on or after January 1, 1997 and before January 
1, 1999'' as in the February 22, 2002 proposed rule, the final 
regulations refer to units commencing operation ``in 1997 or 1998.''
    By further example, with regard to units classified as EGUs, the 
proposed rule refers to a unit commencing operation before January 1, 
1997 or in 1997 or 1998 that ``had'' a nameplate capacity greater than 
25 MWe and refers to a unit commencing operation on or after January 1, 
1999 ``with'' the requisite nameplate capacity. With regard to units 
classified as non-EGUs, the proposed rule refers to a unit commencing 
operation before January 1, 1997 or in 1997 or 1998 that ``has'' a 
maximum design heat input greater than 250 mmBtu/hr and refers to a 
unit commencing operation on or after January 1, 1999 ``with'' the 
requisite maximum design heat input. This inconsistent wording 
concerning nameplate capacity and maximum design heat input, where 
sometimes the past tense, sometimes the present tense, and sometimes no 
tense are used for units that had already commenced commercial 
operation in the past, is confusing. The final regulations consistently 
reference nameplate capacity and maximum design heat without using past 
or present tense. The regulations refer to generators ``with'' the 
requisite nameplate capacity and units ``with'' the requisite maximum 
design heat input.
    By further example, the proposed rule refers to EGUs that 
``commenced operation'' before January 1, 1997 or in 1997 or 1998 
serving a generator that ``produced electricity for sale'' and to EGUs 
that ``commence operation'' on or after January 1, 1999 that serve a 
generator that ``produces electricity for sale.'' The proposed rule 
also refers to non-EGUs that ``commenced operation'' before January 1, 
1997 or in 1997 or 1998 that ``did not serve'' a generator ``producing 
electricity for sale'' and to non-EGUs that ``commence operation'' on 
or after January 1, 1999 that ``at no time serves'' or ``at any time 
serves'' a generator ``producing electricity for sale.'' This 
inconsistent wording and use of past and present tenses is also 
confusing. For example, some units in the category of 1999 or later 
commencement of operation have already commenced operation while others 
will commence operation in the future. Yet, the present tense is used 
in reference to all such units. The final regulations consistently 
reference commencement of operation and production of electricity 
without using past or present tense.
    d. Final EGU and non-EGU definitions. For the reasons discussed 
above, we are adopting the following definitions of EGU and non-EGU for 
the NOX SIP Call and the proposed definitions discussed 
above (in footnotes 9, 10, 11, and 12) for the terms ``electricity for 
sale under firm contract to the electric grid,'' ``potential electrical 
output capacity,'' ``nameplate capacity,'' and ``maximum design heat 
input'' used in the EGU and non-EGU definitions. (The EGU and non-EGU 
definitions, and definitions for related terms, adopted today for the 
Section 126 Rule are set forth below in the revised rule language 
accompanying this preamble.)
    (a) The following units are classified as EGUs:
    (1) For non-cogeneration units--
    (A) For units commencing operation before January 1, 1997, a unit 
serving during 1995 or 1966 a generator producing electricity for sale 
under a firm contract to the electric grid.
    (B) For units commencing operation in 1997 or 1998, a unit, serving 
during 1997 or 1998 a generator producing electricity for sale under a 
firm contract to the electric grid.
    (C) For units commencing operation on or after January 1, 1999, a 
unit serving at any time a generator producing electricity for sale.
    (2) For cogeneration units--
    (A) For units commencing operation before January 1, 1997, a unit 
that fails to qualify as an unaffected unit under 40 CFR 72.6(b)(4) for 
1995 or 1996 under the Acid Rain Program.
    (B) For units commencing operation in 1997 or 1998, a unit that 
fails to qualify as an unaffected unit under 40 CFR 72.6(b)(4) for 1997 
or 1998 under the Acid Rain Program.
    (C) For units commencing operation on or after January 1, 1999, a 
unit that fails to qualify as an unaffected unit under 40 CFR 
72.6(b)(4) for any year under the Acid Rain Program.
    (b) The following units are classified as non-EGUs:
    (1) For non-cogeneration units--
    (A) For units commencing operation before January 1, 1997, a unit 
not serving during 1995 or 1996 a generator producing electricity for 
sale under a firm contract to the electric grid.
    (B) For units commencing operation in 1997 or 1998, a unit not 
serving during 1997 or 1998 a generator producing electricity for sale 
under a firm contract to the electric grid.
    (C) For units commencing operation on or after January 1, 1999, a 
unit:
    (i) At no time serving a generator producing electricity for sale; 
or
    (ii) At any time serving a generator with a nameplate capacity of 
25 MWe or less producing electricity for sale, and with the potential 
to use no more than 50 percent of the potential electrical output 
capacity of the unit.
    (2) For cogeneration units--
    (A) For units commencing operation before January 1, 1997, a unit 
that qualifies as an unaffected unit under 40 CFR 72.6(b)(4) for 1995 
and 1996 under the Acid Rain Program.
    (B) For units commencing operation in 1997 or 1998, a unit that 
qualifies as an unaffected unit under 40 CFR 72.6(b)(4) for 1997 and 
1998 under the Acid Rain Program.
    (C) For units commencing on or after January 1, 1999, a unit that 
qualifies as an unaffected unit under 40 CFR 72.6(b)(4) for each year 
under the Acid Rain Program.
    (c) Units classified as EGUs or non-EGUs under paragraphs (a) and 
(b) are classified as large or small as follows:
    (1) A unit under paragraph (a) serving a generator with a nameplate 
capacity greater than 25 MWe is a large EGU.

[[Page 21617]]

    (2) A unit under paragraph (a) serving a generator with a nameplate 
capacity equal to or less than 25 MWe is a small EGU.
    (3) A unit under paragraph (b) with a maximum design heat input 
greater than 250 mmBtu/hour is a large non-EGU.
    (4) A unit under paragraph (b) with a maximum design heat input 
equal to or less than 250 mmBtu/hour is a small non-EGU.
5. What Is the Effect on Cogeneration Unit Classification of Applying 
``One-Third Potential Electrical Output Capacity/25 MWe Sales'' 
Criteria, Rather Than the Same Methodology as Used for Other Units?
    The petitioner in Michigan who successfully challenged the lack of 
application of the ``one-third potential electrical output capacity/25 
MWe sales'' criteria to cogeneration units claimed that the failure to 
apply such criteria would result in ``sweeping previously unaffected 
non-EGUs into the EGU category.'' Brief of Petitioner CIBO at 4 
(submitted in Michigan). The petitioner further suggested that, without 
the application of these criteria, ``any sale of electricity will make 
a non-EGU a more stringently regulated EGU.'' Reply Brief of Petitioner 
CIBO at 1 (submitted in Michigan).
    As discussed above, large EGUs and large non-EGUs are included in 
the determination of the amount of a State's significant contribution 
to nonattainment in another State. No reductions by small EGUs or small 
non-EGUs are included in that determination.
    Neither the petitioner nor any party that commented in the 
NOX SIP Call or the Section 126 rulemakings identified any 
specific, existing cogeneration units that, without the application of 
the ``one-third potential electrical output capacity/25 MWe sales'' 
criteria, would be classified as large EGUs but that, with the 
application of such criteria, would be classified as either large or 
small non-EGUs. In fact, one commenter supporting the ``one-third 
potential electrical output capacity/25 MWe'' sales criteria stated 
that applying the criteria to the NOX SIP Call ``would not 
alter the Agency's baseline emissions inventory, since cogeneration 
units were, for the most part, classified correctly as non-EGUs in 
EPA's current data base.'' See Responses to the 2007 Baseline Sub-
Inventory Information and Significant Comments for the Final 
NOX SIP Call (63 FR 57356, October 27, 1998), May 1999 at 9. 
In our proposed rule in response to the Court's decision, we again 
asked commenters to identify any specific, existing cogeneration units 
that, without the application of the ``one-third potential electrical 
output capacity/25 MWe sales'' criteria, would be classified as large 
EGUs but that, with the application of such criteria, would be 
classified as either large or small non-EGUs. One commenter stated that 
up to 16 cogeneration units in the paper and pulp industry units would 
be affected by the change in EGU definition. However, the commenter not 
only failed to provide the names of any specific units but also stated 
that it lacked sufficient information to determine whether any of the 
units were selling electricity under firm contract to the grid. In 
short, the commenter did not really know whether the 16 units would 
actually be treated as EGUs if the ``one-third potential electrical 
output capacity/25 MWe sales'' criteria were not applied.
    For today's final rule, in light of the lack of such specific 
information in the comments, we were unable to identify any small 
cogeneration units whose classification as EGUs or non-EGUs will change 
in light of the changes in the EGU and non-EGU definitions adopted in 
the final rule. The only exception may be for units at the Tobaccoville 
facility, which are addressed above. However, for the reasons discussed 
above, we will consider reclassification of these units during the SIP 
revision approval process. Further, it is conceivable that there are 
other small cogeneration units that need to be reclassified from EGUs 
to non-EGUs and that, therefore, further adjustments to the budgets of 
particular States may be necessary. We will also make such further 
adjustments during the SIP approval process when we receive the 
information necessary to support such reclassifications of small 
cogeneration units. Because we anticipate that few, if any, units 
currently treated in the budgets as EGUs qualify as small cogeneration 
units, we expect few, if any, revisions to the budgets resulting from 
today's final rule, and if any revisions do result, we anticipate that 
they will be very small and will not affect most States.
    In order to facilitate the SIP approval process, we request 
participants in the process of developing SIP revisions in response to 
today's final rule to identify by name, location, and plant and point 
identification any cogeneration unit that they believe should be 
classified as a large or small non-EGU under the methodology in today's 
final rule and that would have been classified differently as a large 
or small EGU under the methodology in the proposed rule. We also 
request identification by name, location, and plant and point 
identification of any cogeneration unit that should be classified as a 
large or small EGU under today's final rule methodology and that would 
have been classified as a large or small non-EGU under the proposed 
methodology. In addition, we request information supporting any claimed 
EGU, non-EGU, large, or small classification of each identified unit.
    Persons that identify units as cogeneration units or small 
cogeneration units (under the ``one-third potential electrical output 
capacity/25 MWe sales'' criteria) should submit the following 
information to confirm their identification:
    (1) A description of the facility to demonstrate that the facility 
meets the definition of a ``cogeneration unit'' under 40 CFR 72.2.
    (2) Data describing the annual electricity sales from the unit for 
every year from the unit's commencement of operation through the 
present. To provide this information, persons should submit the same 
form as they used to report the information to the EIA, or if they have 
not reported the information to EIA, provide the same information on 
annual electricity sales as was or would have been required to be 
reported to EIA.
    (3) Information stating and supporting the value of the unit's 
maximum design heat input.

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

    In the February 22, 2002 action, we proposed that highly cost-
effective controls are available for stationary IC engines. We proposed 
to assign a 90 percent emissions 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 proposed to assign a percent 
reduction from within the range of 82 to 91 percent. Based on available 
data regarding demonstrated costs, effectiveness, availability, and 
feasibility of low emission combustion (LEC) technology, and 
consideration of comments received in response to the proposal, we 
stated that we would determine a percent reduction number to use in 
calculating this portion of the NOX SIP Call budget 
decrease.
    Today, we are recalculating the budgets to reflect a control level 
of 82 percent for the natural gas-fired lean-burn IC engines. Because 
the vast majority of large natural gas-fired IC engines are lean burn, 
we are applying the 82 percent reduction to all large natural gas-fired 
IC engines for the

[[Page 21618]]

purpose of setting this portion of the budget. For the other IC engine 
subcategories (diesel and dual fuel) we are using 90 percent control, 
as proposed.
1. Determination of Highly Cost-Effective Reductions and Budgets
    As described in the NOX SIP Call final rule, after 
determining the degree to which NOX emissions, as a whole 
from the particular upwind States, contribute to downwind nonattainment 
or maintenance problems, we determined whether any amounts of the 
NOX emissions may be eliminated through controls that, on a 
cost-per-ton basis, may be considered to be highly cost effective. By 
examining the cost effectiveness of NOX controls, we 
determined that an average of approximately $2,000 per ton removed is 
highly cost effective. We first projected the total amount of 
NOX emissions that sources in each covered State would emit, 
accounting for their projected growth and measures required under the 
CAA, in 2007. We then projected the total amount of NOX 
emissions that each of those States would emit in 2007 if each State 
applied the highly-cost effective measures (the State's budget). The 
difference between the 2007 base inventory and the budget for each 
State is that State's ``significant contribution'' to downwind 
nonattainment. For a more detailed discussion of the determination of 
cost-effective reductions and budgets, see the October 27, 1998 
NOX SIP Call (63 FR 57399-57403 and 57405, respectively).
2. What Are the Key Comments We Received Regarding IC Engines?
    The following describes key comments regarding IC engines and 
provides our responses. Additional comments and responses are contained 
in the Response to Comments (RTC) document associated with this 
rulemaking. Related information is also contained in the Technical 
Support Document (TSD) (revised version) associated with this 
rulemaking.
a. Level of NOX Control
    (1) NOX uncontrolled emission rate.
    Comment: Several commenters suggested that we should rely on the 
July 2000 AP-42 emission factor documents (Docket No. OAR-2001-0008, 
Item Nos. XII-D-09 and XII-D-10) for the average uncontrolled emission 
rates [11.7 g/bhp-hr (grams per brake horsepower-hour) for 2-stroke 
engines and 15.1 g/bhp-hr for 4-stroke engines]. The commenters object 
to our use of a higher value (16.8 g/bhp-hr) as the uncontrolled 
level.\19\ The commenters state that the July 2000 AP-42 factors are 
best because:
---------------------------------------------------------------------------

    \19\ Note: Use of a higher uncontrolled value would result in a 
higher overall percentage control value. For example, assuming a 
control level of 3.0 g/bhp-hr the percentage control value would be 
82 percent using 16.8 g/bhp-hr as the uncontrolled level and 75 
percent using 12.0 as the uncontrolled level.
---------------------------------------------------------------------------

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

    \20\ See footnotes ``(a)'' to Tables 3.2-1 and 3.2-2 in the July 
2000 AP-42 document.
---------------------------------------------------------------------------

    Comment: Commenters state that our 16.8 g/bhp-hr average is derived 
from ``mostly'' new engine models in 1991, not the entire, current 
population of existing engines. According to commenters, the 1994 ACT 
document numbers are not representative of older NOX SIP 
Call type engines, the details of the data are unavailable, and the 
16.8 value cannot be replicated. The commenters indicate that our 
weighted average approach does not correspond to engine models in the 
NOX SIP Call population, that the NOX 1994 ACT 
reflects 1991 manufacturer's letters for new, 4-stroke engines, and 
that we need to make these letters available.
    Response: We have examined data from the pipeline industry, data 
recently collected by the Agency, and data from the 1994 ACT document 
(see RTC or TSD for details). These include data from large engines 
covered by the NOX SIP Call as suggested by some commenters. 
We believe the data support the 16.8 value proposed, as described 
below.
    Emissions data compiled by three pipeline industry companies 
provide support to the 16.8 g/bhp-hr value proposed by us or a slightly 
higher value. Test data are contained in two letters to the Ozone 
Transport Commission (OTC) in November 2000. Based on a survey of LEC 
retrofit installation in NOX SIP Call States, two pipeline 
companies in a November 20, 2000 letter to the OTC,\21\ presented data 
on pre-LEC and post-LEC emissions for 86 engines in NOX SIP 
Call States. Most of the engines are relatively large, at 2000 hp or 
greater. Table 1 of the letter summarizes the data and states that the 
average uncontrolled NOX emissions level for these 86 
engines is 16.8 g/bhp-hr, identical to the level we proposed. 
Considering only those engines greater than or equal to 2,000 hp, there 
are 66 engines with an average uncontrolled emissions rate of 18.2 g/
hp-hr (see RTC or TSD for details). Additional data in the same letter 
provide pre-LEC and post-LEC data for 20 engines. The letter states 
that the average uncontrolled NOX emissions for the 20 
engines is 14.1 g/bhp-hr. Another major pipeline company also sent a 
letter (November 22, 2000) to the OTC presenting uncontrolled and RACT 
emission rates for 62 engines retrofit with LEC (see RTC or TSD for 
details). The average uncontrolled emission rate, considering all 62 
engines from this data set, is 17.6 g/bhp-hr. The weighted average of 
these three data sets is 17.5 g/bhp-hr.\22\
---------------------------------------------------------------------------

    \21\ The letter addressed concerns regarding the OTC's 
development of a set of model NOX rules, including rules 
for stationary IC engines.
    \22\ The weighted average was calculated as follows: (66 x 18.2 
+ 14 x 14.1 + 62 x 17.6) divide sum by 142 = 17.5.
---------------------------------------------------------------------------

    In response to comments, we collected additional test data to 
better determine controlled and uncontrolled emission levels from the 
current population of large engines in the NOX SIP Call 
area. Forty-two data points were collected (see RTC or TSD for 
details). The average uncontrolled NOX level from this data 
is 16.7 g/bhp-hr, nearly identical to the proposed level of 16.8 g/bhp-
hr.
    As suggested by commenters, we also examined the available data 
separately for 2- and 4-stroke engines. The test data for the large IC 
engines in the NOX SIP Call area indicate uncontrolled 
levels of 16.4 and 18.9, respectively, for the 2-

[[Page 21619]]

and 4-stroke engines. Using information from the pipeline industry that 
about 85 percent of the engines in the NOX SIP Call area are 
2-stroke, the weighted average of the 16.4 and 18.9 values is 16.8, 
identical to our proposed value.\23\
---------------------------------------------------------------------------

    \23\ For large lean-burn IC engines in the NOX SIP 
Call States, 2-stroke engines represent 83 percent of the total 
large engines and 85 percent of the total large engine horsepower. 
(From INGAA's April 22, 2002 comments, pages 2 and 10.) (Docket No. 
OAR-2001-0008, Item No. XII-D-09).
---------------------------------------------------------------------------

    As described in the 1994 ACT document for stationary IC engines, 
uncontrolled emission levels were provided to us by several engine 
manufacturers. Most manufacturers provided emission data only for 
current production engines, but some included older engine lines as 
well. The manufacturers' letters were placed in the docket. These 
emission levels were tabulated and averaged for engines with similar 
power ratings. For engines greater than 2000 hp, the average 
uncontrolled emission rate from 55 engines is approximately 16.8 g/bhp-
hr. As noted in the TSD, there are several reasons to use the 1994 ACT 
document data. Using the applicable 1994 ACT document is consistent 
with how we treated other non-EGU source categories in the 
NOX SIP Call rulemaking. The 1994 ACT document provides a 
comprehensive look at the IC engine class and has the advantage of 
using a consistent data set for uncontrolled emissions, costs, and 
controls. The 1994 ACT document uses a large data set from which to 
draw conclusions. The 1994 ACT document test data are available in 
several horsepower size categories which is important since we chose 
not to calculate emissions reductions from the smaller IC engines.
    In summary, based on the 1994 ACT document data, the data contained 
in the industry letters to OTC and data we recently collected, there is 
considerable agreement with the 16.8 g/bhp-hr uncontrolled emission 
rate value that we proposed. The data do not support commenters 
suggestion for a lower value, namely 11.7 g/bhp-hr for 2-stroke engines 
and 15.1 g/bhp-hr for 4-stroke engines. Therefore, we conclude that use 
of the 16.8 g/bhp-hr level is appropriate to represent average, 
uncontrolled emissions.
    (2) NOX controlled emission rate with LEC technology.
    Comment: Appendix B to INGAA's April 22, 2002 comment letter lists 
226 lean-burn large and small IC engines in the NOX SIP Call 
States that are retrofit with LEC technology and for which they could 
obtain State NOX permit limits. The average post-control 
NOX permit levels for 2-stroke and 4-stroke engines are 
reported to be 5.0 and 3.7, respectively. The INGAA states that 
NOX permit limits are appropriate for use in calculating the 
average post-control emission rate for lean-burn engines in the 
NOX SIP Call area for the following reasons:
     These engines are located in the NOX 
SIP Call States, and represent the same makes and models as the large 
NOX SIP Call engines,
     These engines operate under State permit limits 
that reflect the emission control achieved by LEC on actual and 
identified individual engines,
     The emission control limits were established as 
the result of a formal regulatory process conducted by the State 
permitting agencies, and
     The LEC retrofits are consistent with the 
technology and costs identified by our NOX SIP Call TSDs.
    Response: We disagree that permit limits are appropriate for 
determining the post-control emission rate. Permit limits generally do 
not reflect the actual emission rate and, thus, are not appropriate to 
determine the emission rates to be expected from installation of LEC 
technology. For example, State records indicate permit limits of 18 and 
8 even though LEC technology is in place and the target emission rate 
in the State RACT plan is 3 for both engines.\24\ In another case, the 
permit level is 3.0, but the actual rate is reported as 1.7.\25\ The 
permit limits for six engines at a station in one State are 3.0 g/bhp-
hr while the test data show emissions at less than 1.1 g/bhp-hr for 
each engine.\26\ We agree with the comment that LEC retrofits are 
consistent with the costs identified by our NOX SIP Call 
TSDs.
---------------------------------------------------------------------------

    \24\ See docket for e-mail from John Patton dated May 30, 2002 
and attachments. (Docket No. OAR-2001-0008, Item No. 0917).
    \25\ See Docket No. OAR-2001-0008, Item No. XII-M-01 for 
November 20, 2000 letter, appendices A & B.
    \26\ See Docket No. OAR-2001-0008, Item No. 0921 for June 5, 
2002 fax from Randy Hamilton.
---------------------------------------------------------------------------

    Further, if we were to use permit rates, it makes no sense to 
ignore permit limits set in areas outside the NOX SIP Call 
region. California and Texas permits, for example, have very low 
emission rates for IC engines.\27\ The permit levels suggested by 
commenters are limited because the permits generally reflect RACT 
requirements. However, highly cost-effective controls under the 
NOX SIP Call are not limited to RACT-level stringency and 
should take into account improvements in control efficiency and cost 
effectiveness that have occurred over the last several years since the 
RACT generation of controls.
---------------------------------------------------------------------------

    \27\ Ventura County Rule 74.9 (in effect September 1989 to 
December 1993) applied to engines greater than or equal to 100 hp 
and required 125 ppm (1.7 g/bhp-hr) or 80 percent control. Current 
Ventura County Rule 74.9 requires 45 ppmv (0.6 g/bhp-hr) or 94 
percent control. For best available retrofit control technology, 
California Air Resources Board selected for engines greater than or 
equal to 100 hp 65 ppm (0.9 g/bhp-hr) or 90 percent control, based 
on Sacramento Air Quality Management Division Rule 412. In Texas, 
requirements applicable in Houston are 0.5-0.6 g/bhp-hr for lean-
burn engines.
---------------------------------------------------------------------------

    Comment: Commenters state that data we used to support the proposed 
controlled levels \28\ are for new or rebuilt engines--not retrofits--
and therefore, cannot be relied upon. They suggest we should use 
NOX limits for engines retrofit with LEC in State permits 
and that the permits suggest no more than a 70 percent reduction.\29\ 
Several commenters indicate it is important to examine the specific 
engines in the NOX SIP Call States to determine whether the 
reductions we assumed are achievable. Comments suggest that industry 
experience through RACT retrofits, has demonstrated that the stringent 
emission rates of 1.5 to 3.0 g/bhp-hr are not achievable on many 
engines and the average emission reduction to be expected for LEC 
retrofits is 70 percent. Comments from the New Hampshire Department of 
Environmental Services expressed support for a 90 percent control 
level.
---------------------------------------------------------------------------

    \28\ We proposed to select a value within the range of 82 to 91 
percent control (1.5-3.0 g/bhp-hr controlled level assuming 16.8 
uncontrolled level) based primarily on information in the 1994 ACT 
document.
    \29\ This equates to a 5.0 g/bhp-hr limit, assuming an 
uncontrolled level of 16.8 g/bhp-hr.
---------------------------------------------------------------------------

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

[[Page 21620]]

for large engine models found in the NOX SIP Call area.
---------------------------------------------------------------------------

    \30\ For example, November 30, 1998 letter from INGAA to EPA 
(Docket No. OAR-2001-0008, Item No. 0919), February 16, 1999 memo 
from INGAA to Tom Helms, EPA (Docket No. OAR-2001-0008, Item No. 
XII-K-38), and April 26, 2002 comment letter from Kinder Morgan 
(Natural Gas Pipeline Company of America) (Docket No. OAR-2001-0008, 
Item No. XII-D-24).
---------------------------------------------------------------------------

    The INGAA in their April 22, 2002 comments, identified the most 
common models of large natural gas transmission engines in the 
NOX SIP Call area. In addition, INGAA identified engines 
that had been retrofit with LEC in the NOX SIP Call area. In 
response to these comments, we contacted the various EPA Regional 
Offices to obtain information on specific large lean-burn engines used 
by the gas pipeline industry that have been retrofit with LEC in the 
NOX SIP Call area. Data from the EPA Regional Offices and 
other emission test results were obtained. The results for large 
engines in the NOX SIP Call area show that 43 of the 58 
tests have NOX emission levels at or below 3.0 g/bhp-hr (see 
RTC or TSD for details). The LEC technology retrofit on these large 
engines achieved, on average, an emission rate of 2.3 g/bhp-hr.
    As suggested by commenters, we also examined the available data 
separately for 2- and 4-stroke engines (see TSD for details). Test data 
for the large IC engines in the NOX SIP Call area indicate 
controlled levels of 2.3 and 2.5, respectively, for the 2- and 4-stroke 
engines. Assuming 85 percent of the engines in the NOX SIP 
Call area are 2-stroke, the weighted average of the 2.3 and 2.5 values 
is 2.3.
    As described in the TSD, looking at a broader set of data yields 
similar results. That is, considering data from large engines both 
inside and outside the NOX SIP Call area shows that 60 of 
the 79 tests have NOX emission levels at or below 3.0 g/bhp-
hr (see TSD for details). The LEC technology retrofit on these large 
engines achieved, on average, an emission rate of 2.2 g/bhp-hr. 
Considering the similarity of the resulting average controlled emission 
rates and the ample set of data for large engines in the NOX 
SIP Call area, we agree with commenters that it is reasonable to focus 
on the set of data for large engines in the NOX SIP Call 
area.
    The set of data for large engines in the NOX SIP Call 
area cover 80 percent of the engine models in the NOX SIP 
Call area. However, emission rates for some of the engine models for 
which test data are not available are likely to be higher than the 2.3 
average value. For example, Worthington and Nordberg engines are known 
to be difficult to retrofit. One vendor reported achieving a level of 6 
g/bhp-hr for certain Worthington engines.\31\ As noted in the TSD, a 
Worthington UTC 165 in New York reduced NOX emissions to 4.4 
g/hp-hr. A pipeline company commented that they operate six Worthington 
engines and that 4.0 g/bhp-hr is their targeted emission reduction 
level, based on vendor projections.\32\ Thus, it appears that a 4.0 to 
6.0 g/bhp-hr level is achievable on these difficult to retrofit 
Worthington engines. At this time, we believe that 5.0 g/bhp-hr is a 
reasonable emission rate, on average, for engines known to be difficult 
to retrofit. Although not all of the 20 percent of engine models for 
which test data are not available are likely to be difficult to 
retrofit, we believe it is reasonable to treat these engines as one 
group and to conservatively assume that this group of engines would 
achieve a 5.0 level, on average.
---------------------------------------------------------------------------

    \31\ ``Stationary Reciprocating Internal Combustion Engines: 
Updated Information on NOX Emissions and Control 
Techniques,'' EC/R Incorporated, September 1, 2000, page 4-5 (Docket 
No. OAR-2001-0008, Item No. XII-K-43).
    \32\ Docket No. OAR-2001-0008, Item No. XII-D-24.
---------------------------------------------------------------------------

    In summary, based on the available test data, we believe it is 
reasonable to assume about 80 percent of the large engines in the 
NOX SIP Call area are able to meet a 2.3 level, on average, 
and that 20 percent are able to meet a 5.0 level, on average with LEC 
technology. Thus, calculating the weighted average for installation of 
LEC technology retrofit on all of these large IC engines results in a 
2.8 g/bhp-hr limit.
    Comment: In their letter of October 25, 2002, INGAA commented that 
the additional data we collected includes data on 27 lean-burn engines 
and the data indicate that the average retrofit LEC technology level is 
2.7 g/bhp-hr for 2-stroke engines, which represent the bulk of the 
engine horsepower in the NOX SIP Call area. In addition, 
INGAA commented that the data reported on the IC engines retrofit with 
LEC have a number of problems, including scarcity of before-and-after 
tests on the same engine, and the absence of data on load or other 
operating conditions of the tested engines. The INGAA also commented 
that the vendor references we cited indicate that the retrofit LEC 
technology is intended to result in emissions to meet a 3 g/bhp-hr 
limit.
    Response: We agree that test data cited by INGAA and the vendor 
estimates indicate that the average retrofit LEC technology level is in 
the 2.7 to 3.0 g/bhp-hr range. We also note that these comments are 
fairly consistent with a November 20, 2000 letter to the OTC from two 
pipeline companies which recommended a limit of no less than 3.0 g/bhp-
hr, with an alternative standard of no more than 80 percent reduction. 
This range is also consistent with the available test data for large 
engines in the NOX SIP Call area which indicate an average 
value of 2.8 g/bhp-hr.
    As INGAA points out, there is some uncertainty in the test data 
due, for example, to lack of data on operating load in some cases. In 
addition, there is some uncertainty because of the lack of data for all 
engine models. Due to this uncertainty, we believe it is appropriate to 
consider a minor adjustment to the control level suggested by the test 
data. The difference between selecting a 2.8 value (suggested primarily 
by the test data) or a 3.0 value (suggested by some pipeline companies 
and vendor comments) for the controlled emission rate is very small, 
only a 1 percent difference. That is, the two values result in either 
an 82 percent or 83 percent control level, assuming a 16.8 g/bhp-hr 
uncontrolled value. Thus, while our analysis of the test data indicates 
a 2.8 value is reasonable, in view of the recommended 3.0 level from 
some industry and vendor comments, and considering the uncertainties in 
the data and the small difference in the resultant control level, we 
believe it is appropriate to select the upper range of the control 
levels proposed, namely 3.0 g/bhp-hr.
    (3) Level of NOX control to assume for budget 
calculation.
    Comment: In the proposed rule we invited comment on how many of the 
large natural gas-fired IC engines are from lean-burn operation and how 
many are from rich-burn. The INGAA commented that 156 of the 168 large 
engines listed in the NOX SIP Call Inventory that have 
Standard Industrial Classification codes associated with the natural 
gas transmission industry are lean-burn models, with one exception. For 
the purposes of calculating the IC engine portion of the NOX 
SIP Call State budgets, INGAA recommended that we should assume that 
all the large natural gas-fired stationary engines in the inventory are 
lean burn. Comments from the State of Indiana indicated there are no 
large, rich-burn engines in the State.
    Response: As pointed out by the commenters, the vast majority of 
large IC engines in the NOX SIP Call inventory are natural 
gas-fired lean-burn engines. Furthermore, the emission inventory does 
not contain sufficient detail to determine exactly which engines are 
lean burn and which are not. For these reasons, we agree with the 
comment that it is reasonable to assume that all the large natural gas 
stationary engines in the inventory are lean burn for the purposes of 
calculating the IC engine portion of the NOX SIP Call State 
budgets.

[[Page 21621]]

    Comment: As discussed above, we received comments on the 
uncontrolled and controlled levels for natural gas-fired engines. 
Several commenters recommended no more than 70 percent reduction, based 
primarily on permit data. One State recommended 90 percent reduction.
    Response: The percent reduction determination is based primarily on 
two factors--the uncontrolled and controlled levels--which are 
discussed above. We reviewed information submitted by commenters and 
collected additional data in response to concerns raised by commenters. 
Considering all of the available data, we have determined that the 
appropriate uncontrolled and controlled values are 16.8 and 3.0, 
respectively. As a result, we believe that application of highly cost-
effective controls on large natural gas-fired IC engines will achieve, 
on average, an 82 percent reduction. Therefore, 82 percent is used for 
purposes of calculating this portion of the NOX SIP Call 
budget.
b. Flexibility/Averaging
    Comment: Several commenters noted that the response of IC engines 
to retrofit NOX controls is highly variable and that the 
average NOX reduction used to calculate the NOX 
SIP Call budgets is not necessarily the level that all large engines 
can achieve. Because of this variability, these commenters suggest that 
State air agencies should assign NOX reductions to the 
owners or operators of IC engines, but not attempt a uniform definition 
of the required control technology, or specification of a single 
compliance limit. The commenters suggest that we include language in 
the final rule stating that we recommend, and will approve, SIPs which 
provide that owners or operators of large engines in the NOX 
SIP Call inventory develop company-specific compliance plans to 
demonstrate achievement of NOX reductions. In addition to 
describing the standards for emissions reductions averaging in the 
final rule, commenters suggested that we issue a guidance letter to the 
States urging them to provide flexibility for IC engines and explaining 
how to do that. The industry lists a number of advantages to the 
company compliance plan approach to meeting the engine NOX 
reductions in the NOX SIP Call Rule:
     Engine owners and operators would accept 
enforceable and verifiable measures to control engines to meet assigned 
NOX SIP Call reductions.
     Based on the company compliance plans, States 
would be able to clearly demonstrate to us their compliance with Phase 
II of the NOX SIP Call.
     The EPA, States, and regulated companies would 
not have to work through the technical confusion of definitions of 
lean-burn and rich-burn engines, and whether individual engines could 
in fact achieve certain control levels with a prescribed control 
technology.
     Compliance with NOX SIP Call 
requirements could be achieved with minimum impacts on cost, natural 
gas capacity, and operational reliability.
    One pipeline company stated that we should encourage States 
implementing the engine portion of the NOX SIP Call to focus 
primarily on the population of large engines which emitted more than 1 
ton per day during the 1995 ozone season and which formed the basis for 
our calculation of the desired emissions reductions. Retrofitting this 
population of engines is more feasible and is the most cost-effective 
method for achieving reductions due to economies achieved by 
controlling larger sources.
    Response: We addressed this issue in a guidance memorandum dated 
August 22, 2002. As discussed in the reference memorandum,\33\ where 
States choose to regulate large IC engines, we encourage the States to 
allow owners and operators of large IC engines the flexibility to 
achieve the NOX tons/season reductions by selecting from 
among a variety of technologies or a combination of technologies 
applied to various sizes and types of IC engines. Flexibility would be 
helpful as companies take into account that individual engines or 
engine models may respond differently to control equipment. That is, 
while certain controls are known to have a specific average control 
effectiveness for an engine population, some individual engines that 
install the controls would be expected to be above and some below that 
average control level, simply because it is an average. Although the 
issue of flexibility does not affect the setting of the NOX 
SIP Call budget, it is an important issue as States take steps to meet 
their NOX SIP Call requirements.
---------------------------------------------------------------------------

    \33\ August 22, 2002 memo from Lydia Wegman to EPA Regional Air 
Directors providing guidance on issues related to stationary IC 
engines and the NOX SIP Call (Docket No. OAR-2001-0008, 
Item No. XII-C-115).
---------------------------------------------------------------------------

    During the SIP development process, the States may establish an 
NOX tons/season emissions decrease target for individual 
companies and then provide the companies with the opportunity to 
develop a plan that would achieve the needed emissions reductions. The 
companies may select from a variety of control measures to apply at 
their various emission units in the State, or portion of the State, 
affected under the NOX SIP Call. These control measures 
would be adopted as part of the SIP and must yield enforceable and 
demonstrable reductions equal to the NOX tons/season 
reductions required by the State. What is important from our 
perspective is that the State, through a SIP revision, demonstrate that 
all the control measures contained in the SIP are collectively adequate 
to provide for compliance with the State's NOX budget during 
the 2007 ozone season.
c. New Source Review (NSR) Exclusion
    Comment: Some commenters stated that the final rule should provide 
an exemption from NSR regulations for IC engines that install 
NOX controls for compliance with the NOX SIP 
Call. According to the commenters, installation of the required 
emission controls will likely result in increases in emissions of 
carbon monoxide (CO) and/or volatile organic compounds (VOC); the 
resulting emission increases could exceed the ``significant'' levels 
for CO or VOC, thereby subjecting those facilities to either prevention 
of significant deterioration (PSD) or nonattainment NSR permit 
requirements; and, this would increase the compliance costs. Pipeline 
industry comments request that we expressly state in our final remand 
response that installing controls on IC engines to meet NOX 
SIP Call requirements will not trigger NSR for NOX under the 
``actual-to-potential'' test. Commenters also request that we state 
that installing retrofit controls is an ``environmentally beneficial'' 
action that qualifies for an NSR exclusion for any collateral increases 
of other criteria pollutants.
    Response: As discussed in the earlier referenced memorandum,\34\ 
where sources choose to install combustion modification technology to 
reduce emissions of NOX at natural gas-fired lean-burn IC 
engines, we believe this action should be considered by permitting 
authorities for exclusion from major NSR as a pollution control 
project. Further, the memo indicates that, unless information regarding 
a specific case indicates otherwise, installation of combustion 
modification technology for the purpose of reducing NOX 
emissions at natural gas-fired lean-burn IC engines can be presumed, by 
its nature, to be environmentally beneficial. We recently stated our 
intent to modify

[[Page 21622]]

the ``actual to potential'' test.\35\ In most cases, we believe that 
LEC retrofit technology will not increase emissions of CO or VOC to the 
extent that NSR is triggered; in many cases, emissions of CO and VOC 
will decrease with the installation of LEC technology (see RTC document 
for details). Thus, we believe that the permit process will not hamper 
efforts to install controls.
---------------------------------------------------------------------------

    \34\ August 22, 2002 memo from Lydia Wegman to EPA Regional Air 
Directors providing guidance on issues related to stationary IC 
engines and the NOX SIP Call (Docket No. OAR-2001-0008, 
Item No. XII-C-115).
    \35\ In the Federal Register on December 31, 2002, EPA codified/
finalized the Pollution Prevention Project exclusion. In Table 2, 
Environmentally Beneficial Pollution Control Projects, LEC for IC 
engines is mentioned. However, for the present time, the regulatory 
changes generally only affect States with delegation authority to 
implement the Federal PSD program which became effective on March 3, 
2003. For States continuing to implement their existing programs for 
another 2 to 3 years, the August 22, 2002 guidance memo mentioned 
above, is appropriate.
---------------------------------------------------------------------------

d. Early Reductions
    Comments: Industry comments recommend that we provide specific 
guidance in the final rule that directs States to recognize emissions 
reductions that companies have made since 1995, and that companies 
should be allowed credit for emissions reductions achieved since 1995 
for determining compliance with their portion of the States' emissions 
reductions required to meet the emissions budgets.
    Response: We addressed this issue in the above mentioned guidance 
memorandum. As discussed in the memo, we agree that creditable 
reductions with respect to the NOX SIP Call may include 
emission controls in place during or prior to 1995, as well as after 
1995 for the large engines. In addition, States generally may use 
emissions reductions achieved after 1995 at the smaller engines as part 
of their NOX SIP Call budget demonstration.
e. Presumptive Technology
    Comment: Because of the variability of gas pipeline engines in the 
NOX SIP Call area, industry commenters suggest that State 
air agencies should assign NOX reductions to the owners or 
operators of IC engines, but not attempt a uniform definition of the 
required control technology, or specification of a single compliance 
limit. There is significant variability both in the pre-controlled 
emission levels of lean-burn engines and in the response of any 
particular engine to the retrofit installation of LEC technology.
    Response: As suggested, we have dropped from the final rulemaking 
the definition of LEC retrofit technology and the presumption of 
NOX reduction effectiveness. The definition and presumption 
are not necessary to establish the NOX budget. Nevertheless, 
we believe that, on average, LEC technology achieves an 82 percent 
reduction from uncontrolled emissions.
f. Monitoring
    Comment: Industry comments recommended that we should specify in 
the final rule the types of monitoring that will be acceptable.
    Response: We addressed this issue in the August 22, 2002 guidance 
memorandum. As discussed in the memo, acceptable monitoring is not 
limited to those monitoring methods such as continuous or predictive 
emissions measurement systems that rely on automated data collection 
from instruments. Non-automated monitoring may provide a reasonable 
assurance of compliance for IC engines provided such periodic 
monitoring is sufficient to yield reliable data for the relevant time 
periods determined by the emission standard.
g. Emission Factors for 2- and 4-Stroke Engines
    Comment: Some commenters asked us to use separate emission factors 
for 2- and 4-stroke engines.
    Response: As described above, we examined ``uncontrolled'' 
emissions from 2- and 4-stroke engines separately and concluded that 
the data support the 16.8 value we proposed. We also examined the 
available ``controlled'' data separately for 2- and 4-stroke engines. 
Test data for the large IC engines in the NOX SIP Call area 
indicate controlled levels of 2.3 and 2.5, respectively, for the 2- and 
4-stroke engines. Assuming 85 percent of the engines in the 
NOX SIP Call area are 2-stroke, the weighted average of the 
2.3 and 2.5 values is 2.3. Thus, because the 2-stroke engines dominate 
the NOX SIP Call inventory and the controlled value for the 
4-stroke engines is nearly identical, there is no benefit from using 
separate emission factors. Furthermore, our emission inventory is not 
detailed enough to identify which engines are 2-or 4-stroke engines; 
thus, we need to use an average value to represent the combined 
population of large, lean-burn engines. We believe the difference 
between the two values is relatively small, there is a great deal of 
overlap, some key industry reports also use a single value, the 
available data for 2- and 4-stroke engines support the value we 
proposed, control techniques are the same, and we have already 
subdivided the category of IC engines. For these reasons, we have 
chosen not to further subdivide the IC engines category.

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

    In today's final action, we are finalizing our inclusion of only 
certain portions of Georgia and Missouri in the NOX SIP Call 
and revising their statewide budgets to reflect our inclusion of only 
sources in the fine grid parts of both States.
    As stated in the final NOX SIP Call Rule, air pollution 
travels across county and State lines and it is essential for State 
governments and air pollution control agencies to cooperate to solve 
the problem. Ozone transport is a regional problem and we believe that 
NOX emissions reductions across the region in amounts 
achievable by cost-effective controls is a reasonable step to take to 
mitigate ozone nonattainment in downwind States (63 FR 57362). These 
emissions reductions, in combination with other measures, will enable 
attainment and maintenance of the 1-hour ozone NAAQs in the OTAG 
region.\36\ Since the problem is a regional one, we believe that all 
States in the NOX SIP Call area must cooperate to solve the 
problem.
---------------------------------------------------------------------------

    \36\ OTAG Policy Paper approved by the Policy Group on December 
4, 1995.
---------------------------------------------------------------------------

    By way of background, we took final action on October 27, 1998, in 
the NOX SIP Call Rule, to prohibit those amounts of 
NOX emissions which significantly contribute to downwind 
nonattainment. See, NOX SIP Call Rule, 63 FR 57356. We 
determined the amount of emissions that significantly contribute to 
downwind nonattainment by evaluating:
    (1) The overall nature of the ozone problem (i.e. ``collective 
contribution''); (2) the extent of the downwind nonattainment problems 
to which the upwind State's emissions are linked, including the ambient 
impact of controls required under the CAA or otherwise implemented in 
the downwind areas; (3) the ambient impact of the emissions from the 
upwind State's sources on the downwind nonattainment problems; and (4) 
the availability of highly cost-effective control measures for upwind 
emissions. (63 FR 57376, October 27, 1998).
    As part of our analyses of the air quality factors we considered 
the OTAG modeling and our State-specific modeling. Id. at 57384.
    In its modeling, OTAG used grids drawn across most of the eastern 
half of the United States. The ``fine grid'' has grid cells of 
approximately 12 kilometers on each side (144 square kilometers). The 
``coarse grid'' extends beyond the perimeter of the fine grid and has 
cells with 36 kilometer

[[Page 21623]]

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.\37\ (OTAG Technical 
Supporting Document, chapter 2, pg. 6; also available at the following 
Web site: http://www.epa.gov/ttn/naaqs/ozone/rto/otag/finalrpt/). 
Specifically, the fine grid-coarse grid line was drawn to:
---------------------------------------------------------------------------

    \37\ In addition to these three factors, OTAG considered three 
other factors in establishing the geographic resolution, overall 
size, and the extent of the fine grid. These other factors dealt 
with the computer limitations and the resolution of available model 
inputs.
---------------------------------------------------------------------------

    (1) Include within the fine grid as many of the 1-hour ozone 
nonattainment problem areas as possible and still stay within the 
computer and model run time constraints, (2) avoid dividing any 
individual major urban area between the fine grid and coarse grid, and 
(3) be located along an area of relatively low emissions density. As a 
result, the fine grid-coarse grid line did not track State boundaries, 
and Missouri and Georgia were among several States that were split 
between the fine and coarse grids. Eastern Missouri and northern 
Georgia were in the fine grid while western Missouri and southern 
Georgia were in the coarse grid.
    The analysis OTAG conducted found that the emission controls they 
examined, when modeled in the entire coarse grid (i.e., all States and 
portions of States in the OTAG region that are in the coarse grid) had 
little impact on high 1-hour ozone levels in the downwind ozone problem 
areas of the fine grid.\38\ The OTAG also concluded from its modeling 
that the closer an upwind area is to the downwind area, the greater the 
benefits in the downwind area from controls in the upwind area.
---------------------------------------------------------------------------

    \38\ The OTAG recommendation on Major Modeling/Air Quality 
Conclusions approved by the Policy Group, June 3, 1997 (62 FR 60318, 
appendix B, November 7, 1997).
---------------------------------------------------------------------------

    Examining the 2007 Base Case \39\ 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.
---------------------------------------------------------------------------

    \39\ The 2007 Base Case includes all control measures required 
by the CAA.
---------------------------------------------------------------------------

    A number of parties, including certain States as well as industry 
and labor groups challenged the NOX SIP Call Rule. 
Specifically, Georgia and Missouri industry petitioners claimed that 
our record supported inclusion of only eastern Missouri and northern 
Georgia as contributing significantly to downwind nonattainment. The DC 
Circuit Court upheld our finding of significant contribution for almost 
all jurisdictions covered by the NOX SIP Call, but vacated 
and remanded our inclusion of Georgia and Missouri. Michigan v. EPA, 
213 F. 3d 663 (DC Cir. 2000), cert. denied, 121 S. Ct. 1225 (2001) 
(Michigan). The Court found that the NOX budgets for these 
States ``not only encompass the whole state but are calculated on the 
basis of hypothesized cutbacks from areas that have not been shown to 
have made significant contributions.'' Id. at 684 (emphasis in 
original). The Court also found that ``EPA must first establish that 
there is a measurable contribution'' from the coarse grid portion of 
the State before holding the coarse grid portion of the State 
responsible for the significant contribution of downwind ozone 
nonattainment in another state. Id. at 683-84 (emphasis in original).
    Subsequently, we made revisions to the NOX SIP Call Rule 
emissions budgets in the Technical Amendments Rulemakings (64 FR 26298, 
May 14, 1999); (65 FR 11222, March 2, 2000). A group of Missouri 
Utilities and the City of Independence, Missouri challenged our budget 
for the State of Missouri and requested the Court to vacate the entire 
budget under both the 1-hour and 8-hour ozone standards. In its 
decision, the Court found ``it prudent to vacate and remand the TAs 
[technical amendments] insofar as they include[d] a budget for Missouri 
under any ozone standard.'' Appalachian Power Company v. EPA, 251 F. 3d 
1026, 1041 (2001). The Court also found that ``[w]here the agency's own 
data inculpate part of a state and not another, EPA should honor the 
resulting findings.'' Id. at 1040.
    In response to the Court's decisions, we issued the February 22, 
2002 rule proposing to include only fine grid parts of Georgia and 
Missouri in the NOX SIP Call. We explained that the Court in 
Michigan did not call into question our ``proposition that the fine 
grid portion of each State should be considered to make a significant 
contribution downwind.'' (67 FR 8413).
    We stated that based on OTAG's modeling and recommendations, the 
technical support documents for the NOX SIP Call rulemaking, 
and emissions data, we believed that emissions in the fine grid parts 
of Georgia and Missouri comprise a measurable or material portion of 
the entire State's significant contribution to downwind nonattainment. 
In addition, we explained that we had performed State-by-State modeling 
for Georgia and Missouri as part of the final NOX SIP Call 
rulemaking. The results of this modeling showed that emissions in both 
Georgia and Missouri make a significant contribution to nonattainment 
in other States. Moreover, we explained that the Court pointed out that 
the fine grid portion of each State lies closer to downwind 
nonattainment areas. Michigan v. EPA, 213 F. 3d at 683.
    We further explained that for purposes of determining budgets for 
the fine grid portion, we believed that OTAG modeling should be used 
with an adjustment for counties that straddle the line separating the 
fine grid and coarse grid. We also explained that we would base our 
overall NOX emissions budgets on all counties which lie 
wholly contained in the fine grid, as a result of the difficulties and 
uncertainties associated with accurately dividing the fine and coarse 
grid for individual counties. Counties that straddle the fine grid-
coarse grid line or which are completely within the coarse grid would 
be excluded from the budget calculations for Georgia and Missouri. As a 
result, we proposed to revise the NOX budgets for Georgia 
and Missouri to include only the fine grid portions of these States.
    In response to our proposal, several commenters asserted that our 
inclusion of the fine grid portions of the States of Georgia and 
Missouri was not supported by reliable data in light of the Court's 
ruling in Michigan and requested additional air quality modeling for 
these portions. A couple of commenters submitted air quality modeling 
and one commenter requested reconsideration of our inclusion of sources 
that lie ``just inside the fine grid.'' Other commenters argued that no 
NOX SIP Call exists for the States of Georgia and Missouri 
in light of the Court's holdings in Michigan and Appalachian Power 
(Technical Amendments Case). They further argued that the Agency must 
make independent findings of significant contribution for both eastern 
Missouri and northern Georgia, respectively. One commenter also 
contended that we could not base our findings on existing data but must

[[Page 21624]]

consider new circumstances and any changes in air quality since 
promulgation of the NOX SIP Call Rule. Another commenter 
requested that we not exclude sources in any county that partially lies 
within the coarse grid area in the affected States.
    Under today's final rulemaking, we are finalizing our proposal to 
include the fine grid portions of Georgia and Missouri as contributing 
significantly to downwind nonattainment. We believe this is consistent 
with the Court's pronouncements in Michigan. Specifically, the Court 
found that ``[t]he fine grid modeling of parts of Missouri and Georgia 
showed emissions in the aggregate meeting the EPA's threshold 
`contribution' criteria.'' Michigan, 213 F.3d at 683 (emphasis in 
original). The Court also found that it was ``no mere techno-fortuity 
that the fine grid included enough of Missouri to include the city of 
St. Louis and enough of Georgia to include Atlanta: [because] the fine 
grid portions of both states are closest to other nonattainment areas, 
such as Chicago and Birmingham, and generally higher ozone density.'' 
Id.
    We see no reason to revise the existing determination that sources 
in the fine grid parts of Georgia and Missouri contribute significantly 
to downwind nonattainment. As explained in our proposal, the basis for 
our determination continues to be: (1) The results of our State-by-
State modeling; (2) the relatively high amount of NOX 
emissions per square mile in the fine grid portions of each State; and 
(3) the closeness of the fine grid portions of each State to downwind 
nonattainment areas compared to the coarse grid portions (67 FR 8414).
    Additionally, we note that Georgia and Missouri industry 
petitioners maintained, as we believe, that there was record support 
for inclusion of emissions from the eastern half of Missouri and the 
northern-two thirds of Georgia as contributing to downwind ozone 
problems. As the Court stated, ``[a]ccordingly, they say the 
NOX Budget for Missouri and Georgia should be based solely 
on those emissions.'' Michigan 213 F.3d at 684. We have also evaluated 
the modeling submitted by one commenter and we find that this modeling 
does not refute our conclusion that sources in the fine grid portions 
of Georgia and Missouri contribute significantly to downwind 
nonattainment, as discussed below.
    Accordingly, consistent with the Court's finding in Michigan, we 
have revised the NOX emissions budgets for Georgia and 
Missouri to include only the fine grid portions of these States. The 
counties that are included in the calculation of NOX budgets 
for each of these States are listed in Table 1.

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


[[Page 21625]]

    We are not making a finding today as to whether sources in the 
coarse grid portions of Georgia and/or Missouri make a measurable or 
material part of the significant contribution of each of these States, 
respectively. In addition, apart from our findings relating to the 
NOX SIP Call, a State may, of course, assess the in-State 
impacts of NOX emissions from its coarse grid area, and 
impose additional NOX reductions, beyond the NOX 
SIP Call requirements in the fine grid, as necessary to demonstrate 
attainment or maintenance of the ozone NAAQS in the State.
    Comment: Several commenters supported our inclusion of the fine 
grid portions of Missouri and Georgia. One commenter requested that we 
not exclude sources within any county that partially lies within the 
coarse grid area in the affected States.
    Response: Today's action is in response to the court's decision 
that vacated our inclusion of the entire States of Georgia and 
Missouri. Michigan v. EPA, 213 F.3d 663. (DC Cir. 2000), cert. denied, 
121 S. Ct. 1225 (2001) (Michigan). ``EPA must first establish that 
there is a measurable contribution'' from the coarse grid portion of 
the State before holding the coarse grid portion responsible for the 
significant contribution of downwind ozone nonattainment in another 
state. Id. at 683-84 (emphasis in original).
    As explained in our February 22, 2002 proposal, ``because of 
difficulties and uncertainties with accurately dividing emissions 
between the fine and coarse grid of individual counties for the purpose 
of setting overall NOX emissions budgets, we believe that 
the calculation of the emissions budgets should be based on all 
counties which are wholly contained within the fine grid.'' (67 FR 
8415). We believe this is consistent with the Court's ruling. Thus, we 
are finalizing the budgets for Georgia and Missouri to include only 
those counties that lie wholly within the fine grid portions of both 
States as described above.
    Comment: One commenter requested the reconsideration of our 
inclusion of sources that are ``just inside the fine grid.'' This 
commenter based its request on modeling showing that sources in Georgia 
south of 32.67 degrees latitude do not significantly contribute to 
nonattainment ozone areas in downwind States.
    Response: We have evaluated the modeling submitted by this 
commenter and found that the modeling does not refute the overall 
conclusions we have drawn concerning the impacts of NOX 
emissions in the relevant geographic areas. The commenter quantified 
the contribution from those emissions in Georgia south of 32.67 degrees 
latitude (i.e., southern Georgia) by modeling the four OTAG episodes 
with emissions in southern Georgia removed (i.e., zero-out). The 
results of this modeling, as presented by the commenter, suggest that 
emissions in southern Georgia contribute less than 2 parts per billion 
(ppb) to the peak daily 1-hour ozone in 1-hour nonattainment areas 
outside of Georgia in each of the four episodes. In view of these 
results, the commenter contends that the contribution from southern 
Georgia to all downwind nonattainment areas is not significant since 
the contribution is less than the 2 ppb screening criteria used by EPA 
in the NOX SIP Call to identify those upwind State-to-
downwind nonattainment area linkages that were clearly not significant. 
However, the commenter misinterpreted the definition of EPA's 2 ppb 
screening criteria by limiting the analysis of contribution to just the 
episode peak concentration in the downwind areas. By doing so, the 
contractor did not consider or present any data to evaluate the 
contribution from southern Georgia to other ozone exceedances (i.e., 
less than the peak value but exceeding the NAAQS) predicted in each 
downwind area. For example, southern Georgia may not impact the 
predicted episode peak for the 1-hour ozone standard in Birmingham by 2 
ppb, but southern Georgia could have contributed at least 2 ppb to one 
or more of the other 88 exceedances in Birmingham. Unfortunately, the 
commenter did not provide any data to permit an examination of the 
contribution of emissions from southern Georgia to all exceedances in 
downwind nonattainment areas. Thus, the comment that southern Georgia 
does not significantly contribute to downwind nonattainment because 
they did not examine all contributions above 2 ppb.
    Thus, to the extent that the sources are modeled by the commenter 
in a county that falls within the fine grid part of Georgia, we do not 
believe we should reconsider its inclusion in the NOX SIP 
Call.
    Comment: Several commenters stated that our inclusion of portions 
of the State of Georgia was not supported by reliable data and sound 
science especially in light of Michigan, ``that remanded and vacated in 
its entirety [the inclusion of whole states of Georgia and Missouri],'' 
due to ``EPA's unsupportable determination of significant 
contribution.'' Several commenters also stated that we had failed to 
provide data to support the inclusion of portions of the State of 
Georgia that are within the fine grid. Another commenter argued that we 
had failed to provide information to support inclusion of affected 
sources in Georgia.
    Response: In Michigan, the DC Circuit Court held that [t]he fine 
grid modeling of parts of Missouri and Georgia showed emissions in the 
aggregate meeting the EPA's threshold contribution criteria.'' 
Michigan, 213 F.3d at 683 (emphasis in original). The Court noted that 
``EPA's explanation and technique make clear that emissions from the 
fine grid areas may have been the sole source of the finding.'' Id.
    The Court also found that it was ``no mere techno-fortuity that the 
fine grid included enough of Missouri to include the city of St. Louis 
and enough of Georgia to include Atlanta: the[se] fine grid portions of 
both states are closest to other nonattainment areas, such as Chicago 
and Birmingham, and generally higher ozone density.'' Id. However, the 
Court vacated and remanded the NOX SIP Call budgets for the 
States of Georgia and Missouri finding that the budgets ``not only 
encompass the whole state but are calculated on the basis of 
hypothesized cutbacks from areas that have not been shown to have made 
significant contributions.'' Id at 684. (emphasis in original). The 
Court further held that ``EPA must first establish that there is a 
measurable contribution'' from the coarse grid portion of the State 
before holding the coarse grid portion of the State responsible for the 
significant contribution of downwind ozone nonattainment in another 
State. Id. In Appalachian Power Company v. EPA, 251 F. 3d 1026, 1040-1 
(2001), the Court found that ``insofar as the TAs [technical 
amendments] include a statewide Missouri emission budget they are 
unlawful under Michigan.''
    Thus, the Court did not call into question the proposition that the 
fine grid portions of Georgia and Missouri should be considered as 
making a significant contribution to downwind nonattainment. We also 
note that Georgia and Missouri industry petitioners maintained that, as 
we believe, there was record support for inclusion of emissions from 
the eastern half of Missouri and the northern-two thirds of Georgia as 
contributing to downwind ozone problems. Michigan, 213 F. 3d at 681.
    In addition, in the NOX SIP Call Rule, we found that 
``[s]ources that are closer to the nonattainment area tend to have much 
larger effects on the air quality than sources that are far away.'' (63 
FR 25919.) Further, OTAG's technical findings and recommendations 
concluded that areas located in the fine grid should receive additional 
controls

[[Page 21626]]

because they contribute to ozone in other areas within the fine grid.
    Today's rulemaking finalizes our revision of the budgets for 
Georgia and Missouri to reflect the Court's pronouncements in Michigan. 
This is also consistent with OTAG's recommendations and findings. We 
have revised neither our existing determination nor our bases for the 
determination that sources in the fine grid portion of Georgia and 
Missouri are contributing significantly to downwind nonattainment. We 
are revising the NOX budgets for Georgia and Missouri to 
reflect the inclusion of only the sources that are within the fine grid 
portions of both States. Accordingly, we also continue to rely on the 
Technical Support Document and Notice of Data Availability which are 
the underlying documents for the NOX SIP Call Rule.
    Comment: One commenter argued that the Court vacated our 
determination of significant contribution for all of Missouri in 
Michigan, and therefore, we no longer have a basis for including any 
portion of Missouri in the NOX SIP Call. The commenter also 
argued that we made no significant contribution finding for eastern 
Missouri but rather based our findings on emissions from the whole 
State.
    Response: We disagree with the comment. As stated elsewhere in this 
rule, with respect to the fine grid parts of Georgia and Missouri, the 
Court found that ``the fine grid modeling of parts of Missouri and 
Georgia showed emissions in the aggregate meeting the EPA's threshold 
contribution criteria.'' Michigan, 213 F.3d. at 683. We also note that 
Georgia and Missouri industry petitioners maintained that there was 
record support for inclusion of emissions from the eastern half of 
Missouri and the northern-two thirds of Georgia as contributing to 
downwind ozone problems. Id., at 681. The OTAG's recommendations and 
findings concluded that areas located in the fine grid should receive 
additional controls because they contribute to ozone in other areas 
within the fine grid. In addition, our modeling showed that emissions 
in both Georgia and Missouri make a significant contribution to 
nonattainment in other areas. Therefore, we believe there is record 
support for inclusion of eastern Missouri.
    Comment: One commenter argued that as a result of the vacatur in 
Michigan, we have to justify the inclusion of eastern Missouri in the 
NOX SIP Call taking into consideration facts in existence at 
the time of our proposal.
    Response: We disagree. As stated earlier, the Court found that the 
modeling showed that emissions from the fine grid portions of the 
States of Georgia and Missouri met EPA's ``threshold `contribution' 
criteria.'' The Court also let stand OTAG's modeling analyses (except 
with respect to Wisconsin). Thus, the inclusion of eastern Missouri 
accords with the Court pronouncements on the fine grid/coarse grid.
    In today's rulemaking, we see no reason to revise the existing 
determination that sources in the fine grid parts of Missouri 
contribute significantly to nonattainment downwind. The basis for this 
determination continues to be: (1) The results of our State-by-State 
modeling; (2) the relatively high amount of NOX emissions 
per square mile in the fine grid portions of the State; and (3) the 
closeness of the fine grid portions of the State to downwind 
nonattainment areas compared to the coarse grid part.
    Comment: One commenter stated that it was erroneous to continue 
using data that was 4 years old as our basis for the inclusion of 
eastern Missouri in the NOX SIP Call in light of data 
showing that areas receiving measurable contributions from Missouri 
sources are now in attainment of the 1-hour ozone standards.
    Response: We disagree with the comment that downwind ozone 
nonattainment areas have achieved attainment of the 1-hour ozone 
standards. More specifically, Chicago has not yet attained the 1-hour 
ozone standard. Chicago's attainment demonstration relies, in part, on 
implementation of Missouri's statewide NOX rule, approved by 
EPA into the SIP. The NOX SIP Call reductions in Missouri are needed 
for Chicago to attain/maintain the 1-hour standard.
    Although the attainment plan was approved, we believe it is 
important to point out that there are inherent uncertainties in the 
plan, including hourly emission estimates and emissions growth 
projections. Further, without the NOX SIP Call, Missouri may 
come under increased pressure to relax the existing State rule, which 
could jeopardize attainment in Chicago. Additionally, the SIP-approved 
State rule has not yet been implemented and was, in fact, recently 
revised by the State.
    The reductions are highly cost effective and would also help offset 
emissions from a number of large sources locating upwind of St. Louis 
and avoid very costly local controls in the future.
    We disagree that a new emissions inventory is necessary that takes 
into account Missouri's statewide NOX rule and other post-
1998 CAA rules. Because SIPs are constantly changing, it is impractical 
to revise emission inventories and modeling analyses each time changes 
are made. For example, the NOX limits the commenter cites 
have since been revised by the State and are yet to be approved by EPA.
    Further, completing the NOX SIP Call in Missouri is an 
equitable approach. It would be inequitable to use 2003 air quality 
analysis for Missouri but to hold other NOX SIP Call States 
to the 1998 analysis. It should also be noted that we intend to review 
the NOX SIP Call Rule and will make adjustments if necessary 
(63 FR 57428).
    This program is the single most important measure to reduce 
interstate pollution in the short term. Reductions of NOX 
emissions from the program will enhance the protection of public health 
for over 100 million people in the eastern half of the United States--
including people in Missouri. It is a centerpiece of the clean air 
plans for many cities, including the Chicago area.
    Comments: Another commenter stated that the current State of 
Missouri control regulations would achieve greater NOX 
emissions and greater improvements than the NOX SIP Call.
    Response: We disagree. Missouri adopted and, in December 2000, we 
approved a statewide NOX rule which requires emissions 
reductions in the eastern third of the State and lesser reductions in 
the remainder of the State for large EGUs. While we approved this rule 
because it helped address the ozone nonattainment issue in St Louis, we 
did not find that this rule addressed the significant transport of 
NOX to other areas that we had identified in the 
NOX SIP Call. Revisions to the statewide NOX rule 
were adopted on April 24, 2003 and were submitted as a SIP revision on 
September 18, 2003.
    Both the SIP-approved statewide NOX rule and the 
revisions to the rule submitted to EPA would achieve less 
NOX emissions reductions than implementation of the 
NOX SIP Call. Missouri's current and proposed revised 
NOX rules are less stringent than the NOX SIP 
Call requirements. The emissions reductions under the NOX 
SIP Call are greater by about 20 percent statewide and 40 percent in 
the fine grid compared to the SIP-approved Missouri rule. The 
NOX SIP Call also offers the advantages of a cap and trade 
program, including certainty of emissions reductions; the State rules 
have no emissions cap. While the current State rule and the SIP 
revisions may

[[Page 21627]]

accomplish reductions similar to those under the NOX SIP 
Call in the short-term, without an emissions cap there is no assurance 
that the required reductions will continue in the long-term.
    Reductions are more effective in preventing interstate transport to 
key downwind areas under the NOX SIP Call as they must occur 
in the eastern part of Missouri and trading is not allowed between 
eastern and western Missouri EGUs. The Missouri rules spread the 
requirement for NOX reductions throughout the entire State. 
Thus, the emissions reductions are not focused in the geographical area 
of interest.
    The NOX SIP Call budget also includes reductions in 
emissions from large cement kilns, industrial boilers, and stationary 
IC engines. The NOX SIP Call would allow fewer emissions 
statewide, as shown in Table 2 below.

          Table 2.--Comparison of Ozone Reductions in the NOX SIP Call and the Missouri Statewide Rule
----------------------------------------------------------------------------------------------------------------
  EGU emissions  (tons per ozone season)             Fine grid                          Statewide
----------------------------------------------------------------------------------------------------------------
Actual 2001 Emissions....................  30,872......................  60,102
NOX SIP Call.............................  13,400 cap..................  37,600 a in 2001b c
MO current SIP-approved rule.............  23,100 in 2001c.............  46,900 in 2001c
MO revised rule..........................  19,100 in 2001d c...........  49,600 in 2001c
----------------------------------------------------------------------------------------------------------------
a. Assuming Missouri's current SIP-approved rule remains effective in the coarse grid (reductions from rule are
  included in the attainment demonstrations for St. Louis and Chicago).
b. The table only compares EGU emissions; the NOX SIP Call requires 2,900 tons additional NOX reductions due to
  controls on cement, industrial boilers and engines in the fine grid.
c. Estimated emissions based on actual 2001 heat input; emissions after 2001 would be higher as the State rule
  has no cap.

    Further, we informed the State of some problem areas in their 
recent rule revisions. In addition to the issues above, there are other 
SIP-approvability concerns with the Missouri statewide rule which make 
it likely that the rule would have to undergo further revision. These 
include concerns about the credibility of early reduction credits which 
appear not to be actual surplus.

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

    We calculated Alabama's and Michigan's budgets in the same manner 
as we did for Georgia and Missouri, as described above. While no 
petitioners raised any issues concerning the inclusion of only parts of 
Alabama and Michigan in the NOX SIP Call, the Court's 
reasoning regarding Georgia and Missouri applies equally to Alabama and 
Michigan. Based on the information in the record, we revised the 
NOX budgets for Alabama and Michigan to reflect reductions 
only in the fine grid portions of these States.\40\ Again, like Georgia 
and Missouri, we see no reason to disturb the determination that 
sources in the fine grid contribute significantly to nonattainment 
downwind; the fine grid portions of both Alabama and Michigan are 
closer to downwind 1-hour ozone nonattainment areas than the coarse 
grid parts of these States. Also, the amount of NOX 
emissions per square mile in the fine grid portion of Alabama is nearly 
60 percent greater than in the coarse grid part; and in Michigan the 
fine grid NOX emissions per square mile are more than 500 
percent greater than emissions per square mile in the coarse grid 
portion of the State. Counties in Michigan and Alabama which straddle 
the fine grid-coarse grid are excluded from the budget calculations as 
described above for Georgia and Missouri. We believe this approach is 
consistent with the holding in Michigan concerning Georgia and Missouri 
and is justified as provided above.\41\
    The counties in Alabama and Michigan that are included in the 
calculation of NOX budgets for each of these States are 
listed in Table 3.
---------------------------------------------------------------------------

    \40\ Both Georgia and Missouri submitted Phase I SIPs which 
included only the fine grid portion of the States.
    \41\ Pursuant to the court's order lifting the stay of the SIP 
submission obligation, the 20 States, including Alabama, Michigan, 
and the District of Columbia, were required to submit SIPs in 
response to the NOX SIP Call by October 30, 2000. As 
discussed above, in letters dated April 11, 2000 to State Governors, 
we informed the States that remained subject to the NOX 
SIP Call that they could choose to submit SIPs meeting only the 
Phase I emissions budget for each State. With respect to Alabama and 
Michigan, we also provided that they could choose to submit SIPs 
that address emissions only in the fine grid portion of the State. 
Alabama and Michigan submitted Phase I SIPs which included only the 
fine grid portion of the States.

          Table 3.--Fine Grid Counties in Alabama and Michigan
 
 
 
Alabama:
  Autauga Co
  Bibb Co
  Blount Co
  Calhoun Co
  Chambers Co
  Cherokee Co
  Chilton Co
  Clay Co
  Cleburne Co
  Colbert Co
  Coosa Co
  Cullman Co
  Dallas Co
  De Kalb Co
  Elmore Co
  Etowah Co
  Fayette Co
  Franklin Co
  Greene Co
  Hale Co
  Jackson Co
  Jefferson Co
  Lamar Co
  Lauderdale Co
  Lawrence Co
  Lee Co
  Limestone Co
  Macon Co
  Madison Co
  Marion Co
  Marshall Co
  Morgan Co
  Perry Co
  Pickens Co
  Randolph Co
  Russell Co
  St. Clair Co
  Shelby Co
  Sumter Co
  Talladega Co
  Tallapoosa Co
  Tuscaloosa Co
  Walker Co
  Winston Co
Michigan:
  Allegan Co
  Barry Co
  Bay Co
  Berrien Co
  Branch Co
  Calhoun Co
  Cass Co
  Clinton Co
  Eaton Co
  Genesee Co
  Gratiot Co
  Hillsdale Co
  Ingham Co
  Ionia Co
  Isabella Co
  Jackson Co
  Kalamazoo Co

[[Page 21628]]

 
  Kent Co
  Lapeer Co
  Lenawee Co
  Livingston Co
  Macomb Co
  Mecosta Co
  Midland Co
  Monroe Co
  Montcalm Co
  Muskegon Co
  Newaygo Co
  Oakland Co
  Oceana Co
  Ottawa Co
  Saginaw Co
  St. Clair Co
  St. Joseph Co
  Sanilac Co
  Shiawassee Co
  Tuscola Co
  Van Buren Co
  Washtenaw Co
  Wayne Co
 

E. What Modifications Are Being Made to the NOX Emissions 
Budgets?

    In today's final action, in a change from the proposed rule, we are 
excluding certain small cogeneration units from the definition of EGU. 
All other cogeneration units and other non-acid rain units will remain 
as EGUs. As a result, it makes sense to require States to include in 
their Phase II SIPs the anticipated emissions reductions from non-Acid 
Rain units. However, since, as discussed below, States seem to have 
already included non-Acid Rain units in the Phase I SIPs, today's 
action concerning the EGU definition will have little or no effect on 
State budgets and required reductions.
    We are also finalizing technical changes to the EGU definition in 
the NOX SIP Call to make it consistent with the definition 
of EGU used in the Section 126 Rule. Since the EGU definition 
establishes the dividing line between the EGU and non-EGU categories, 
the changes to the EGU definition result in corresponding changes to 
the non-EGU definition in the NOX SIP Call, which make it 
consistent with the non-EGU definition in the Section 126 Rule. Today's 
action concerning these definitions does not result in any specific 
revisions to the budgets established under the final NOX SIP 
Call and the Technical Amendments.
    We are recalculating the budgets to reflect a control level of 82 
percent for the natural gas-fired lean-burn IC engines. For the other 
IC engine subcategories (diesel and dual fuel) we are using 90 percent 
control, as proposed.
    We are calculating the budgets for Georgia, Missouri, Alabama, and 
Michigan assuming controls in all counties that are fully located in 
the fine grid, as discussed in sections II.C. and II.D. The partial 
State budgets for Georgia, Missouri, Alabama, and Michigan in today's 
action are calculated using IC engine control, as well as the 
definition of EGUs as described above.
    Our budgets are shown in Tables 4 and 5. For States that are 
required to submit Phase I SIPs, Table 6 shows the Phase I and final 
budgets and the incremental difference between the two budgets. We are 
requiring States that have submitted SIPs that meet only the Phase I 
budget to supplement their control plans with rules that will meet the 
Phase II increment.
    The budget numbers in Tables 4 and 5 are based on the 
NOX SIP Call emission inventory as revised in the 
``Technical Amendment to the Finding of Significant Contribution and 
Rulemaking for Certain States for Purposes of Reducing Regional 
Transport of Ozone,'' which was published on March 2, 2000. The EPA 
first published minor changes to the NOX SIP Call emission 
inventory in a Technical Amendment published May 14, 1999, in response 
to comments on the 2007 baseline sub-inventory in the NOX 
SIP Call published October 27, 1998. After the first Technical 
Amendment was published, EPA received further comments stating that the 
baseline sub-inventory contained errors. In response to these comments, 
EPA published the second Technical Amendment on March 2, 2000, in which 
changes were made to the baseline inventory and budgets for the 
NOX SIP Call for submitted data which was determined to be 
technically justified.
    In some cases, States have made minor corrections to their 
NOX SIP Call emission inventory as part of their response to 
the NOX SIP Call requirements. States making corrections 
include, for example, Kentucky, Illinois, and Indiana. The EPA has 
evaluated these corrected emission inventories on a case-by-case basis 
and, as appropriate, approved the corrections as part of the rulemaking 
on the State's NOX SIP Call submittal. Today's rulemaking on 
the Phase II NOX SIP Call requirements is based on the 
corrections to the NOX SIP Call emission inventory published 
March 2, 2000 and does not take into account these corrections made in 
the individual State rulemaking actions. Furthermore, additional 
corrections may be made in the future to certain State emission 
inventories due, for example, to the change in the definition of EGU. 
As stated in the NOX SIP Call, ``[t]he control measures that 
the State chooses to require will become the enforceable mechanism 
under the NOX SIP Call'' (63 FR 57426, October 27, 1998). 
The reader should refer to both this final rule and individual 
rulemaking actions on each State's SIP revision in response to the 
NOX SIP Call for more information.
    In cases where the Phase I budget in a State's approved SIP 
revision differs from the EPA budget, due to changes in sources 
approved by EPA, the State is required to achieve the incremental Phase 
II reductions shown in Table 6 in order to meet the full NOX 
SIP Call. In cases where the State has voluntarily submitted, and EPA 
has approved Phase I SIPs with budgets more stringent than required by 
EPA, the State is required to achieve the final budgets shown in Table 
6.

                             Table 4.--State Emissions Budgets and Percent Reduction
                                                  [tons/season]
----------------------------------------------------------------------------------------------------------------
                                                                              Final         Tons       Percent
                            State                             Final  base     budget      reduced     reduction
----------------------------------------------------------------------------------------------------------------
Connecticut.................................................       46,015       42,850        3,165            7
Delaware....................................................       23,797       22,862          935            4
District of Columbia........................................        6,471        6,657         -186           -3
Illinois....................................................      368,870      271,091       97,779           27
Indiana.....................................................      340,654      230,381      110,273           32
Kentucky....................................................      237,413      162,519       74,894           32
Maryland....................................................      103,476       81,947       21,529           21
Massachusetts...............................................       87,095       84,848        2,247            3
New Jersey..................................................      105,489       96,876        8,613            8
New York....................................................      255,658      240,322       15,336            6

[[Page 21629]]

 
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 5.--State Emissions Budgets and Percent Reduction
                                                  [tons/season]
----------------------------------------------------------------------------------------------------------------
                                                                              Final         Tons       Percent
                            State                             Final  base     budget      reduced     reduction
----------------------------------------------------------------------------------------------------------------
Georgia.....................................................      209,914      150,656       59,258           28
Missouri....................................................       92,697       61,406       31,291           34
Alabama.....................................................      169,156      119,827       49,329           29
Michigan....................................................      245,929      190,908       55,021           22
----------------------------------------------------------------------------------------------------------------


                    Table 6--Comparison of Phase I and Phase II State NOX Budgets Comparison
                                                  [tons/season]
----------------------------------------------------------------------------------------------------------------
                                                                                                     Phase II
                              State                                   Phase I      Final  budget    incremental
                                                                      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           6,657               1
Illinois........................................................         278,146         271,091           7,055
Indiana.........................................................         234,625         230,381           4,244
Kentucky........................................................         165,075         162,519           2,556
Maryland........................................................          82,727          81,947             780
Massachusetts...................................................          85,871          84,848           1,023
Michigan........................................................         191,941         190,908           1,033
New Jersey......................................................          95,882          96,876            -994
New York........................................................         241,981         240,322           1,659
North Carolina..................................................         171,332         165,306           6,026
Ohio............................................................         252,282         249,541           2,741
Pennsylvania....................................................         268,158         257,928          10,230
Rhode Island....................................................           9,570           9,378             192
South Carolina..................................................         127,756         123,496           4,260
Tennessee.......................................................         201,163         198,286           2,877
Virginia........................................................         186,689         180,521           6,168
West Virginia...................................................          85,045          83,921           1,124
----------------------------------------------------------------------------------------------------------------

F. How Will the Compliance Supplement Pools Be Handled?

    The compliance supplement pool (CSP) is a pool of allowances that 
can be used in the beginning of the program to provide affected sources 
additional compliance flexibility. The CSP was created to address 
concerns raised by commenters on the NOX SIP Call proposal 
regarding electric reliability during the initial years of the program. 
In the NOX SIP Call Rule, the CSP may be used in the years 
2003 and 2004 (see 63 FR 57428-57430, October 27, 1998, for further 
discussion of the CSP). In Michigan, the DC Circuit Court ruled that 
May 31, 2004, rather than May 1, 2003, is the date by which sources 
must install controls to comply with the NOX SIP Call. 
Consequently, to be consistent with the original 2-year window 
specified in the NOX SIP Call in which we allowed the CSP 
allowances to be used, we are finalizing an extension of the time that 
allowances from the CSP can be used from September 30, 2004 to 
September 30, 2005 for sources with a May 31, 2004 compliance date, and 
to September 30, 2008 for sources with a May 1, 2007 compliance date. 
We are also including CSPs for Georgia and Missouri. As under the 
original NOX SIP Call, Georgia and Missouri may distribute 
the allowances in their respective pools either based on early 
reductions, directly to sources based on a demonstrated need, or by 
some combination of the two methods. (For a more complete discussion of 
how CSP allowances may be distributed under the NOX SIP 
Call, see 63 FR 57429.) The allowances from Georgia's and Missouri's 
CSPs may be used to account for emissions during the 2007 and 2008 
ozone seasons, the first 2 years' ozone

[[Page 21630]]

seasons that sources in those States are required to comply.
    We are not changing the individual State CSP values that were 
finalized in the March 2, 2000 technical corrections to the emission 
budgets (65 FR 11222) with the exception of Alabama, Georgia, Michigan, 
Missouri, and Wisconsin. Changing the State CSPs to reflect the State 
budget changes made in this action would result in minimal impacts on 
the size of any State's CSP. Therefore, we have decided to maintain the 
CSPs at the levels determined in the March 2, 2000 technical amendment 
(with the exception of Alabama, Georgia, Michigan, Missouri, and 
Wisconsin).
    Since required reductions in Georgia, Missouri, Alabama, and 
Michigan finalized under today's final rule are less than the required 
reductions of the October 27, 1998 NOX SIP Call reflecting 
full State emissions budgets, we are making corresponding decreases to 
the CSPs for the portion of each State that is still subject to the 
NOX SIP Call. We have calculated the partial-State CSPs by 
prorating the size of the full-State CSP by the ratio of the reductions 
that we are finalizing for the partial State to the reductions that we 
required in the March 2, 2000 Technical Amendment (65 FR 11222). 
However, even though we are finalizing an 82 percent reduction 
requirement from large natural gas-fired IC engines, to be consistent 
with the way the CSP was calculated in the other States, we assumed a 
90 percent reduction from all large IC engines for purposes of 
calculating the CSP. In addition, since Wisconsin is not being required 
to make reductions at this time, Wisconsin is no longer receiving a 
share of the CSP. (Wisconsin's original CSP was 6,920 tons.) For these 
reasons, the total CSP is now less than 200,000 tons. The revised CSPs 
for Georgia, Missouri, Alabama, and Michigan are shown in Table 7.

                                   Table 7.--Compliance Supplement Pools (CSP)
----------------------------------------------------------------------------------------------------------------
                                                                Partial State
                                              Full State tons    tons reduced                     Partial State
                                               reduced (from   with 90 percent    Full  State      CSP with 90
                                               March 2, 2000      IC engine           low           percent IC
                                                    FR)            control                        engine control
----------------------------------------------------------------------------------------------------------------
GA..........................................           63,582           57,623           11,440           10,728
MO..........................................           62,242           31,291           11,199            5,630
AL..........................................           64,954           49,806           11,687            8,962
MI..........................................           63,118           55,064           11,356            9,907
----------------------------------------------------------------------------------------------------------------

    One commenter (EL Paso Corporation, OAR-2001-0008, XII-D-10), 
commented that IC engines should be allowed to receive reductions from 
the CSP. The commenter asserts that we have failed to recognize that 
the CSP contains NOX allocations generated by IC engines. 
The commenter also claims that because IC engines will also have to be 
retrofitted to comply with the NOX SIP Call they could also 
have reliability problems and, therefore, should be able to receive 
allowances from the CSP.
    Under the NOX SIP Call, the CSP is limited to use by the 
large boilers and turbines that are in the NOX Budget 
Trading Program. Because IC engines are not in the NOX 
Budget Trading Program, they are not eligible to receive allowances 
from the CSP. States have two options for making the pool available to 
sources in the trading program. One option is to distribute some or all 
of the pool to sources that generate early reductions during ozone 
seasons prior to May 1, 2003. The second option is to run a public 
process to provide tons to sources that demonstrate a need for a 
compliance extension. The pool was created to help that group of 
sources meet compliance deadlines without jeopardizing electric 
reliability. It was not created to address reliability problems in 
other sectors.

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

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

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

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

I. How Will Partial-State Trading Be Administered?

    In the final NOX SIP Call, we offered to administer a 
multi-State NOX Budget Trading Program for States affected 
by

[[Page 21631]]

the NOX SIP Call. In today's action, we are including only 
partial State budgets for Alabama, Georgia, Michigan, and Missouri. 
Therefore, we will administer a trading program for the NOX 
SIP Call region that, for these four States, includes only the portion 
of the States we are including in the NOX SIP Call. In the 
final NOX SIP Call, as well as the January 18, 2000 final 
rulemaking on the original eight Section 126 petitions, we authorized 
sources in States affected by either the NOX SIP Call or the 
Section 126 rulemaking to trade with each other through the mechanisms 
of the NOX Budget Trading Program provided certain criteria 
were met. These criteria included that States must be subject to the 
NOX SIP Call and that States must meet the emission control 
level under the final rule for the NOX SIP Call. The 
justification for allowing trading across States is the test of 
significant contribution which underlies both the Section 126 
rulemaking and the NOX SIP Call. Therefore, at this time, 
only sources in the portions of the States for which a finding of 
significant contribution has been made and budgets have been 
established are allowed to participate in trading with sources in 
States which are subject to either the NOX SIP Call or the 
Section 126 rulemaking.
1. How Will Flow Control Be Handled for Georgia and Missouri?
    The NOX SIP Call (63 FR 57356) includes a limitation 
(referred to as ``flow control'') on the use of banked allowances for 
compliance with the requirement to hold allowances covering emissions 
from affected units.\42\ In the NOX SIP Call, we noted that 
banking of allowances may inhibit or prohibit achievement of the 
desired emissions budget in a given [ozone] season since the use of 
banked allowances for compliance for a specific ozone season may result 
in total emissions for affected units exceeding the trading budget for 
that ozone season (63 FR 25902, 25935; May 11, 1998). The trading 
budget reflects the emissions reductions mandated, and found to be 
highly cost effective, under the NOX SIP Call in order to 
prevent significant contribution to nonattainment in downwind States. 
Flow control addresses the potential problem caused by banking by 
continuing to allow unlimited banking of unused allowances but 
discouraging the ``excessive use'' of banked allowances for compliance. 
Id.; see also 63 FR 57473.
---------------------------------------------------------------------------

    \42\ Banked allowances are those allowances that are not used in 
the ozone season for which they are allocated and that are therefore 
carried into the next ozone season. Allowances from the CSP are 
considered banked at the start of the second year of the program. 
See 40 CFR 51.121(b)(2)(ii)(D).
---------------------------------------------------------------------------

    Flow control discourages the excessive use of banked allowances by 
discounting the use of banked allowances for compliance over a 
specified threshold. This threshold was set at 10 percent in the 
NOX SIP Call and applies to the entire NOX SIP 
Call region. The number of banked allowances held in all allowance 
tracking system (ATS) accounts under the trading program is tabulated 
when each ozone season is completed to determine what percentage banked 
allowances comprise of the total multi-State trading budget for the 
next ozone season. If this percentage is greater than 10 percent, flow 
control is triggered, and a withdrawal ratio is established for that 
next ozone season. The withdrawal ratio is calculated by dividing 10 
percent of the total multi-state trading program budget for that next 
ozone season by the total number of banked allowances at the end of the 
completed ozone season. The ratio is then applied to each ATS 
compliance account that holds banked allowances at the end of that next 
ozone season. A unit can use banked allowances for compliance without 
restriction (i.e., on a one-allowance-to-one ton basis) in an amount 
not exceeding the amount in the unit's compliance account times the 
withdrawal ratio. Banked allowances used for compliance in an amount 
exceeding that determined using the withdrawal ratio must be used on a 
two-allowances-for-one ton basis.
    The NOX SIP Call provided that flow control provisions 
apply starting in the second year of the NOX SIP Call 
program. (The first ozone season in which flow control applies and can 
be triggered is referred to as the ``flow control date.'') 
Specifically, the NOX SIP Call established May 1, 2003 as 
the commencement date for the NOX SIP Call program and 
required the flow control provisions to apply starting in the second 
year (i.e., 2004). See 40 CFR 51.121(b)(1)(ii) and (b)(2)(ii)(E). 
Subsequent to the initial NOX SIP Call rulemaking, the D.C. 
Circuit delayed the commencement date for the NOX SIP Call 
program to May 31, 2004, and so the second year of the program--and the 
required flow control date--for State programs beginning in 2004 became 
2005. While the regulations (Sec.  51.121 and part 96) were not 
revised, we have implemented the new flow control date through the 
notice and comment rulemakings for approval of the SIPs. We have 
approved rules under the NOX SIP Call for 17 States and the 
District of Columbia. The approved rules provide for a flow control 
date of 2004 or 2005,\43\ and, as a practical matter the earliest date 
that flow control can be triggered in any of these States and the 
District of Columbia is 2005.\44\
---------------------------------------------------------------------------

    \43\ In approving trading program rules for Connecticut, 
Delaware, District of Columbia, Maryland, Massachusetts, New Jersey, 
New York, and Rhode Island, we approved flow control dates of 2004 
based on the initial NOX SIP Call Rule, under which the 
program started May 1, 2003. (We note that we erroneously approved 
2005 as the flow control date for Pennsylvania, whose program also 
begins in 2003.) After the Court established May 31, 2004 as the 
commencement date for the NOX SIP Call program, we 
approved 2005 as the flow control date for States (i.e., Alabama, 
Illinois, Indiana, Kentucky, North Carolina, South Carolina, 
Tennessee, and West Virginia) whose programs begin in 2004. We also 
approved NOX SIP Call rules for two States (Ohio and 
Virginia) on the condition that a 2005 flow control date be adopted.
    \44\ Although we approved several State programs with a 2004 
flow control date (see footnote number 43), 2005 is the earliest 
year that flow control is likely to be triggered for those States. 
For 2004, the calculation for triggering flow control is the total 
number of banked allowances in accounts as of December 1, 2003 
(i.e., only the unused allowances allocated for 2003 plus the CSP 
allowances for those States with programs beginning in 2003) divided 
by the total trading budgets for the States with programs in effect 
in 2004 (i.e., virtually all States in the NOX SIP Call 
region). Because, for this calculation for 2004, the number of 
States reflected in the numerator is so much smaller than the number 
of States reflected in the denominator, 2005 is effectively the flow 
control date for all States whose programs begin in 2003.
---------------------------------------------------------------------------

    It is our general intent to treat affected units in Georgia and 
Missouri in essentially the same manner as affected units under Phase I 
of the NOX SIP Call. Once Georgia and Missouri submit SIPs 
in accordance with today's rule, we will review these SIPs in light of 
our general intent. As we did in the case of the SIPs submitted by 
States under Phase I of the NOX SIP Call, we will address, 
in the context of reviewing Georgia's and Missouri's SIPs, such issues 
as the flow control provisions and the flow control date and are not 
revising the flow control date in Sec.  51.121 and part 96.
    However, we note that if the flow control provisions in the initial 
NOX SIP Call Rule were applied to Georgia and Missouri, 
potential problems could arise because the units in those States would 
have a flow control date, i.e., the second year (2008) of those States' 
programs, that is 3 years later than the effective 2005 flow control 
date for units in States in Phase I of the NOX SIP Call. We 
will consider and resolve these potential problems when we review 
Georgia's and Missouri's SIPs rather than in today's rule. In order to 
provide guidance to Georgia and Missouri in the development of their 
SIPs, we are discussing below these potential problems.
    The potential problems in applying the flow control provision in 
Sec.  51.121

[[Page 21632]]

and part 96 to Georgia and Missouri are as follows. Allowing 2008 to be 
the flow control date in Georgia (or Missouri) could result in an 
unfair advantage for units in that State over units in other States 
with an effective 2005 flow control date. Specifically, for the 2007 
ozone season when the Georgia (or Missouri) programs begin, banked 
allowances held for Georgia (or Missouri) units or by Georgia (or 
Missouri) companies as of November 30, 2006 could be a contributing 
factor for triggering flow control in 2007 for all other States with 
programs that are in effect. If Georgia (or Missouri) units were to 
help trigger flow control in 2007 but would not be subject to the flow 
control limitation on use of banked allowances in 2007, this would give 
Georgia (or Missouri) units an unfair advantage over units in the other 
States.
    Further, should a 2008 flow control date be approved for Georgia 
(or Missouri), this would allow some companies to circumvent the 
earlier flow control dates established by other States. A company with 
affected units in both Georgia (or Missouri) and a State with an 
effective 2005 flow control date would be particularly advantaged in 
this regard. Such a company could circumvent the earlier flow control 
date by exchanging banked allowances held for its units in the State 
with the 2005 flow control date for 2007 allowances held for its units 
in Georgia (or Missouri). All of these banked allowances could be used 
in Georgia (or Missouri) in 2007 without application of flow control. 
Moreover, a company with only units in States with earlier flow control 
dates could also circumvent, to some extent, the flow control 
provisions of those States. To the extent that the latter company could 
purchase 2007 allowances and sell banked allowances, it could also 
avoid the application of the flow control limitation in 2007. In short, 
allowing a 2008 flow control date for Georgia (or Missouri) would allow 
erosion of the effectiveness of flow control for States with an 
effective 2005 flow control date and would give an unfair advantage to 
some companies.
    We believe these potential problems might be avoided if, under 
Georgia's and Missouri's SIPs, flow control is effective starting in 
the first year (2007) of their programs while CSP allowances for those 
States continue to be treated as banked allowances starting in the 
second year (2008) of their programs. This approach would appear to 
prevent companies from being able to circumvent the effective 2005 flow 
control dates in other States' programs since banked allowances--
whether held by units or companies in Georgia or Missouri or in other 
States--would be subject to flow control in 2007. Transferring banked 
allowances to Georgia or Missouri units or companies would not avoid 
flow control if it is triggered.
    It also appears that applying flow control in the first year of the 
program in Georgia and Missouri would not disadvantage units and 
companies in Georgia and Missouri with regard to their CSP allowances. 
The NOX SIP Call established that the CSP could be used in 
the first 2 years of a State's trading program without the application 
of flow control to the CSP allowances in the first year. Under the 
approach discussed above, the allowances from Georgia's and Missouri's 
CSPs (like the CSPs for other States) would be available for use in the 
first and second years (2007 and 2008 for Georgia and Missouri). 
Because the CSP allowances would not be considered banked until 2008, 
these allowances could be used in the first year of the program (2007) 
without being affected by flow control. Thus, the Georgia and Missouri 
CSP allowances could be used in 2007 without limit regardless of 
whether flow control is triggered at the end of the 2006 ozone season 
and could not trigger flow control at the end of 2007.
    As noted above, today's rule does not establish a flow control date 
for Georgia and Missouri. Instead, we are indicating how we intend to 
address this issue when we review the Georgia and Missouri SIPs, and we 
will consider, in conducting those reviews, the approach discussed 
above and any other approach that is proposed for addressing the issue.

J. What Is the Phase II SIP Submittal Date?

    In today's action, we are setting a date for States to submit SIPs 
meeting the Phase II NOX budgets and the partial State 
budgets for Georgia and Missouri. We believe that an adequate timeframe 
for SIP submittal is 12 months from signature date of this rulemaking. 
We believe that this schedule will allow adequate time for States to 
promulgate rules, and for sources affected by a State's Phase II 
NOX strategy and by Georgia and Missouri's NOX 
strategy to comply with the regulations by the dates in this action. 
Please see section K, below, for a discussion of the compliance dates.
    Comment: Several commenters contend that the range of proposed SIP 
submittal dates (i.e., 6 months to a year from final promulgation of 
this rulemaking, but no later than April 1, 2003) does not allow enough 
time for States to develop a SIP. They noted that this is due to the 
fact that the proposal was published on February 22, 2002 and the 
comment period was scheduled to end on April 15, 2002, and that the 
final rule would not be promulgated in time to allow adequate time for 
States to complete their rulemaking processes. These commenters fell 
into several categories based on their recommendation for a SIP 
submittal date: (1) EPA is not allowing enough time for SIP submittal; 
(2) EPA should set a SIP submittal date 12 months from the date of 
final promulgation of this rule; (3) EPA should allow more than 12 
months for States to submit SIPs; and (4) EPA should allow 18 months 
for SIP submittal as authorized in section 110(k)(5).
    Response: After considering these comments, we are requiring that 
SIP revisions be submitted within 12 months after the date of signature 
of this final rule. We believe this is adequate time for States to 
submit SIP revisions reflecting the reductions required by this phase 
of the NOX SIP Call. In response to the court decision in 
Michigan v. EPA, 213 F.3d 663 (DC Cir. 2000), cert. denied, 121 S. Ct. 
1225 (2001), we divided the NOX SIP Call into two phases--
Phase I which accounted for 90 percent of the total reductions required 
by the NOX SIP Call, and Phase II which will achieve 
approximately 10 percent of the total reductions required by the 
NOX SIP Call. Thus, because Phase II of the NOX 
SIP Call requires relatively smaller NOX emissions 
reductions and because it applies to a much smaller subset of sources, 
we believe that 12 months is adequate time for States to develop and 
submit the required SIP revisions. In addition, as earlier stated, this 
action is being taken under section 110(k)(5) which requires SIP 
revisions within a specified period but ``not to exceed 18 months'' 
after a finding of inadequacy by the Agency.
    Initially we had allowed States 12 months for submittal of SIPs 
meeting the full NOX SIP Call, with September 30, 1999 as 
the submission date. On May 25, 1999, in response to a request by 
States challenging the NOX SIP Call, the DC Circuit issued a 
stay of the SIP submission deadline pending further order of the Court. 
Michigan, 213 F. 3d 663 (DC Cir. 2000), cert. denied, 121 S. Ct. 1225 
(2001) (May 25, 1999 order granting stay in part). Subsequently, we 
filed a motion on April 11, 2000, requesting the court to lift the stay 
of the SIP submission date and on June 22, 2000, the court lifted the 
stay and established October 30, 2000, as the new SIP submission date. 
Thus, by setting this submission date, the Court

[[Page 21633]]

recognized the 12-month submission schedule required in the 
NOX SIP Call.
    In setting this timeframe, we also recognize that the proposed 
NOX SIP submittal date of 6 months to 1 year from final 
promulgation of this rulemaking, but no later than April 1, 2003, is no 
longer appropriate due to the February 22, 2002 publication date of the 
proposed rule. We are also aware that some States have lengthy 
rulemaking processes that may require longer than 12 months for full 
adoption of regulations. However, States have the ability to set their 
rulemaking procedures and can provide adequate mechanisms to adopt 
regulations to address interstate transport. Many States already have 
emergency or other shortened procedures in place in order to bypass 
regular rulemaking procedures in certain circumstances. We also note 
that some States have already adopted SIPs that comply fully with the 
NOX SIP Call.
    Moreover, we note that States that fail to submit SIPs within 12 
months are not precluded from submitting plans after that date. Areas 
will not be subject to mandatory sanctions under section 179 of the CAA 
until 18 months after we find that the State failed to submit a plan in 
response to the NOX SIP Call. Furthermore, if the State 
makes a late submission, our approval of that program would serve to 
replace any Federal plan that may have taken effect in the interim. We 
note that States can submit draft plans (i.e., plans that have not 
completed the final steps in the State administrative process) for 
parallel processing. See 47 FR 2703 (June 23, 1982). While this type of 
submission may not preclude a finding of failure to submit, it can help 
ensure that the State program is approved as a SIP revision and as a 
replacement for any promulgated Federal implementation plan in the most 
expeditious manner. Also, as we did for the Phase I NOX SIP 
submittals, the EPA Regional Offices and Headquarters will work closely 
with the States to ensure that approvability issues are quickly 
resolved in order to allow SIPs to be submitted as expeditiously as 
possible.\45\ (Section II.J, OAR-2001-0008, comments XII-D-28, XII-D-
29).
---------------------------------------------------------------------------

    \45\ Technical Support Document, ``Responses to Significant 
Comments on the Proposed Finding of Significant Contribution and 
Rulemaking for Certain States in the OTAG Region for Purposes of 
Reducing Regional Transport of Ozone,'' Docket No. A-96-56, Item No. 
VI-C-01, September 1998.
---------------------------------------------------------------------------

K. What Are the Phase II Compliance Dates?

    We are setting a Phase II compliance date of May 1, 2007. This date 
is 24 months after the SIP submittal date plus the days until the next 
ozone season begins. However, sources already controlled in an approved 
Phase I SIP are required to meet the compliance date stipulated in that 
SIP, including non-Acid Rain EGUs and any cogeneration units that were 
previously classified as EGUs and whose classification changed to non-
EGUs under today's rule.
    In this section, it is important to note that although compliance 
dates are discussed for certain EGUs, non-EGUs, and IC engines, States 
may choose to control other sources. As stated in the original 
NOX SIP Call:

    States are not constrained to adopt measures that mirror the 
measures EPA used in calculating the budgets. In fact, EPA believes 
that many control measures not on the list relied upon to develop 
EPA's proposed budgets are reasonable--especially those, like 
enhanced vehicle inspection and maintenance programs, that yield 
both NOX and VOC emissions reductions. Thus, one State 
may choose to primarily achieve emissions reductions from stationary 
sources while another State may focus emission reductions from the 
mobile source sector. (63 FR 57378, October 27, 1998).
1. How Are We Handling Non-Acid Rain EGUs and Any Cogeneration Units 
That Were Previously Classified as EGUs and Whose Classification 
Changed to Non-EGUs Under Today's Rule?
    We proposed a compliance date of May 31, 2004 (or, if later, the 
date on which the source commences operation) for all Phase II EGUs and 
non-EGUs in Alabama, Connecticut, District of Columbia, Delaware, 
Illinois, Indiana, Kentucky, Massachusetts, Maryland, Michigan, North 
Carolina, New Jersey, New York, Ohio, Pennsylvania, Rhode Island, South 
Carolina, Tennessee, Virginia, and West Virginia. We also proposed a 
compliance date of May 1, 2005 (or, if later, the date on which the 
source commences operation) for all sources in Georgia and Missouri. 
The compliance dates mark the beginning of the periods during which 
units in the trading program must hold at least enough NOX 
allowances to cover their ozone season NOX emissions.
    The proposed compliance date of May 31, 2004 (or, if later, the 
date on which the source commences operation) was designed to provide 
Phase II EGUs and non-EGUs a little over 12 months after the deadline 
for State submission of Phase II SIPs covering such units to install 
any necessary emission controls. In today's rule, we are finalizing a 
deadline of April 1, 2005 for submission of Phase II SIPs. However, we 
believe that for all of the States (except Georgia and Missouri, which 
are addressed separately below), non-Acid Rain EGUs and any 
cogeneration units that were previously classified as EGUs and whose 
classification changed to non-EGUs under today's rule were included in 
the Phase I SIPs that were already submitted.\46\ Several States (i.e., 
Connecticut, District of Columbia, Delaware, Massachusetts, Maryland, 
New Jersey, New York, Pennsylvania, and Rhode Island) have submitted 
SIPs that cover non-Acid Rain EGUs and any cogeneration units whose 
classification changed from EGUs to non-EGUs under today's rule, as 
well as Phase I EGUs and non-EGUs, and require compliance with the 
allowance holding requirement starting May 1, 2003 (or, if later, the 
date on which the source commences operation). The remaining States 
other than Georgia and Missouri (i.e., Alabama, Illinois, Indiana, 
Kentucky, Michigan, North Carolina, Ohio, South Carolina, Tennessee, 
Virginia, and West Virginia) have submitted SIPs that cover non-Acid 
Rain EGUs and any cogeneration units whose classification changed from 
EGUs to non-EGUs under today's rule, as well as Phase I EGUs and non-
EGUs and require compliance starting May 31, 2004 (or, if later, the 
date on which the source commences operation). The coverage of non-Acid 
Rain EGUs and any cogeneration units whose classification changed from 
EGUs to non-EGUs under today's rule is reflected both in the 
applicability provisions in the various SIPs--which provisions cover 
EGUs and non-EGUs without assuming any non-Acid Rain units or any 
cogeneration units--and in the State budget demonstrations and 
allowance allocations--which list the affected units including the non-
Acid Rain EGUs and any cogeneration units whose classification changed 
from EGUs to non-EGUs under today's rule. Although, elsewhere in 
today's final rule, we are revising the definition of EGU and non-EGU, 
we believe that these revisions will require the reclassification of 
few, if any, units as EGUs and non-EGUs and will not make any 
additional units subject to the NOX

[[Page 21634]]

SIP Call. See section II.A.4 of this preamble.\47\
---------------------------------------------------------------------------

    \46\ We note that the non-EGU classification of those 
cogeneration units that have been consistently treated as non-EGUs 
in the NOX SIP Call and the Section 126 Rule was not 
remanded and vacated by the Court, and we maintain that the May 31, 
2004 compliance date for such units is not at issue in today's 
rulemaking. However, even assuming arguendo that their compliance 
date were at issue, there would be no basis for establishing a later 
compliance date since these units (like, e.g., the non-Acid Rain 
EGUs) are already subject to the May 31, 2004 date under the Phase I 
SIPs.
    \47\ To the extent that the revisions of the EGU and non-EGU 
definitions have such an impact on any specific units, we will 
address the matter in connection with our review of the relevant 
State Phase II SIP provisions.
---------------------------------------------------------------------------

    Since all Phase II non-Acid Rain EGUs and any cogeneration units 
whose classification changed from EGUs to non-EGUs under today's rule 
in these States are already subject to a compliance date of May 1, 2003 
or May 31, 2004 (or, if later, the date on which the source commences 
operation), we see no basis for extending the NOX SIP Call 
compliance deadline beyond the date stipulated in the Phase I SIPs 
under which these units are covered. The CAA rests on an 
``overarching'' principle that the NAAQS be achieved as expeditiously 
as possible (63 FR 57356, 57449, October 27, 1998). For example, under 
section 181 of the CAA, the ``primary standard attainment date for 
ozone shall be as expeditiously as practicable but not later than 
[certain statutorily prescribed attainment dates].'' 42 U.S.C. 7511; 
see also 42 U.S.C. 7502(a)(2)(A). The State trading budgets under the 
NOX SIP Call reflect the emissions reductions mandated under 
the NOX SIP Call in order to prevent significant 
contribution to nonattainment in downwind States. Under these 
circumstances, we believe that the CAA's overarching objective of 
expeditious as practicable attainment applies to these units.
    A number of commenters (including several States that have adopted 
SIPs with May 31, 2004 compliance dates for non-Acid Rain EGUs and any 
cogeneration units whose classification changed from EGUs to non-EGUs 
under today's rule) suggested that a compliance date of May 31, 2004 
did not provide sources enough time to install emission controls. Some 
commenters suggested that units should be given 2 years after submittal 
of SIPs to comply. Several other commenters suggested that a compliance 
deadline should be set 1,309 days after the required SIP submittal date 
to be consistent with the DC Circuit's August 30, 2000 order related to 
compliance dates under the NOX SIP Call. As explained above, 
we do not believe it is necessary or appropriate to extend the 
compliance date beyond May 31, 2004 because the States involved have 
already adopted rules requiring non-Acid Rain EGUs and any cogeneration 
units whose classification changed from EGUs to non-EGUs under today's 
rule to comply by that date or earlier. It should also be noted that, 
even if the units had not already been included in the State's Phase I 
SIPs, the 1,309-day period used for setting the May 31, 2004 compliance 
date for Phase I SIPs would not be appropriate for those units. The 
Court's decision to provide units 1,309 days after submittal of SIPs 
was based on the amount of time that we provided units to comply with 
the original NOX SIP Call, which had a compliance deadline 
of May 1, 2003. The original NOX SIP Call required States to 
make significantly more emissions reductions (i.e., all the reductions 
that were subsequently designated as either Phase I or Phase II 
reductions in response to the Court's decision) than the reductions 
(i.e., only the Phase II reductions for non-Acid Rain EGUs and any 
cogeneration units whose classification changed from EGUs to non-EGUs 
under today's rule) addressed here. Greater emissions reductions 
require the installation of more emission controls, which in turn 
requires more resources such as boiler-makers and cranes. The analysis 
that we performed for the proposed Phase II rule shows that less time 
is required to install emission controls for the smaller number of 
Phase II units than the significantly larger number of Phase I units in 
the trading program.
2. What Compliance Date Are We Finalizing for IC Engines and What is 
the Technical Feasibility of This Date?
    We are setting a compliance date for IC engines of May 1, 2007 (or, 
if later, the date on which the source commences operation). This date 
is 24 months after the SIP submittal date plus the days until the next 
ozone season begins.
    Comment: Several commenters from the pipeline industry suggest the 
need to stagger or phase-in the compliance activities over several 
years. Additional comments from the pipeline industry state that we 
ignore time needed to get permits; that we assume 160 engines would be 
off-line in the same winter heating season; and that we failed to 
consider the problem of having multiple engines at one facility subject 
to retrofit requirements during the same short compliance timeframe.
    Comments from 22 citizen groups recommend the May 2004 and May 2005 
dates (or, if later, the date on which the source commences operation), 
as proposed. One State supports the May 2005 compliance deadline 
proposed. All other commenters request that we provide more time than 
was proposed. Another State believes that a minimum of 24 months from 
the date of final SIP submittals is needed for sources to complete the 
necessary construction and installation of controls to comply with the 
Phase II provisions. A third State recommends the compliance date be 
1,309 days after the SIP submittal date. Pipeline industry comments 
generally recommend May 2007 or 36 to 43 months from SIP submittal. 
These commenters refer to the 1998 NOX SIP Call Rule which 
gave 43 months from SIP submittal. Utility group comments also 
recommend we should apply the same 1,309-day compliance period for the 
Phase II NOX SIP Call requirements that applies to sources 
for the Phase I compliance pursuant to the original NOX SIP 
Call Rule schedule.
    Response: The pipeline industry has considerable experience with 
the installation of LEC technology. While there is some evidence that 
installation of controls on a few engines within 1 year is reasonable, 
installing controls on many engines in a narrow timeframe is more 
problematic. As discussed below, we believe that the proposed timeframe 
of about 13 months should be extended to a minimum of 24 months from 
the SIP submittal date and the initial compliance date should occur 
within the ozone season.
    We obtained additional information regarding this issue. One 
manufacturer estimated the time between request for cost proposal and 
contract to be 2 to 5 months and typically 3 to 4 months. It then takes 
4 to 5 months for delivery and an additional 1 month to install and 
commence operation. This adds up to a total of 7 to 11 months.\48\ 
Another manufacturer estimated the time between cost proposal and 
contract is 2 to 4 weeks to obtain bids; 2 to 3 months for selection of 
bids; 12 to 20 weeks for parts delivery to site; and 2 weeks to 1\1/2\ 
months for field installation. Another manufacturer estimated from 
request for cost bids to shipping of parts takes 6 to 8 months for 
delivery and an additional 2 to 4 weeks to install and commence 
operation. This adds up to a total of 6 to 9 months.\49\ Information 
from the Ventura County Air Pollution Control District in California 
estimated 2 weeks to 1 month to install LEC and the total time 
estimated from request for cost proposal and commencing operation of 
LEC was 6 to 9 months. A gas pipeline company, CMS Energy, stated that 
a compliance schedule of 11 months was easy to meet for one to two 
engines but would put a stress on the system for 200 engines. Columbia 
Gas Transmission Corporation installed controls on two engines in 
Bedford County,

[[Page 21635]]

Pennsylvania in 3 days, meeting the 3.0 g/bhp-hr standard set by the 
State.\50\ Thus, there is some agreement that the necessary compliance 
period for installation of controls on a small number of engines is 
less than 1 year.
---------------------------------------------------------------------------

    \48\ See Docket No. OAR-2001-0008, Item No. XII-E-01.
    \49\ See Docket No. OAR-2001-0008, Item No. XII-E-02.
    \50\ See http://www.dieselsupply.com/dscartic.htm for reprint of 
article from May 1998 of ``American Oil & Gas Reporter.''
---------------------------------------------------------------------------

    We disagree with the comment that 160 engines would be off-line at 
the same time. We expect some companies to choose to phase-in 
installation of the control equipment over a 2-year period (or longer 
if the companies begin retrofit activities sooner) and that 
installation activities would occur primarily in the summer along with 
normally scheduled maintenance activities. Further, as noted below, not 
all of the potentially affected IC engines should be expected to need 
LEC retrofits and not in the same timeframe.
    In response to Phase II of the NOX SIP Call, some States 
may seek emissions reductions from source categories other than IC 
engines. Other States have already met their NOX budgets and 
do not need to further control IC engines for purposes of the 
NOX SIP Call. Still other States have met at least a portion 
of the Phase II NOX SIP Call reductions due to emissions 
reductions affecting other source categories contained in their 1-hour 
ozone nonattainment area plans. This reduces the need to retrofit IC 
engines in those States.
    In many cases, companies may use ``early reductions'' achieved at 
IC engines due to other requirements, such as RACT.\51\ For example, 
many IC engines were previously controlled to meet RACT requirements in 
many of the NOX SIP Call States. These emissions reductions 
help States meet their NOX budgets and, thus, decrease the 
amount of additional reductions needed. According to information 
submitted by INGAA, a 1996-97 survey determined that 245 lean burn 
engines in the NOX SIP Call area have LEC.\52\ Many engines 
in the NOX SIP Call area already have decreased 
NOX emissions at rich-burn engines through non-selective 
catalytic reduction (NSCR).\53\ States may choose to credit these 
reductions instead of requiring new reductions at other engines in 
order to meet the SIP budget. Many more NOX reductions are 
likely to result from future maximum achievable control technology 
(MACT) controls at IC engines.\54\ These factors also reduce the need 
to retrofit IC engines in some States.
---------------------------------------------------------------------------

    \51\ Memo from Lydia Wegman, Director, Air Quality Strategies 
and Standards Division, U.S. EPA to Air Division Directors, U.S. EPA 
Regions I-V, VII (August 22, 2002), providing guidance on issues 
related to stationary IC engines and the NOX SIP Call.
    \52\ ``IC Engine OTAG Questions'' document prepared by INGAA, 
February 17, 2000. Many of these engines are smaller than the 
``large'' engines identified in the NOX SIP Call.
    \53\ Alpha Gamma memo of June 19, 2002 (Docket No. OAR-2001-
0008, Item No. 0917).
    \54\ See proposed rule at 67 FR 77845.
---------------------------------------------------------------------------

    We agree with industry comments that pipeline companies will phase-
in the control equipment over a multi-year timeframe. Some companies 
may choose to stagger installation of the controls, beginning even 
before completion of our rulemaking.\55\ Stretching out the 
installation timeframe in this manner would help the companies achieve 
the results on time. Further, companies might choose to install 
controls early in some of their engines in a timeframe that coincides 
with the engine rebuild cycle.\56\ In another case, installation of the 
LEC retrofit kit was estimated to span 3 to 4 weeks and the 
installation was not expected to impact the normal maintenance 
interval.\57\ These approaches will help reduce the time needed to 
install the controls.
---------------------------------------------------------------------------

    \55\ INGAA letter of July 16, 2002 (Docket No. OAR-2001-0008, 
Item No. 0918).
    \56\ A top-end overhaul is generally recommended between 8,000 
and 30,000 hours of operation that entails a cylinder head and 
turbocharger rebuild (see Table 4 from ``Technology 
Characterization: Reciprocating Engines'' prepared by Energy Nexus 
Group for EPA, 2-02).
    \57\ GRI 12-98 report ``NOX Control for Two-Cycle 
Pipeline Reciprocating Engines,'' page 4-11. (Docket No. OAR-2001-
0008, Item No. XII-K-24.)
---------------------------------------------------------------------------

    We believe the industry has demonstrated that multiple engines at 
compressor stations can be successfully retrofitted over a 24-month 
timeframe. For example, in Kentucky, the Jefferson Town Compressor 
Station's RACT compliance plan of April 2000 describes the installation 
of LEC using a phased approach over a 2-year period. Four engines were 
retrofitted during the summer of 2001 and the remaining five engines 
were retrofitted in the summer of 2002. Each engine was expected to be 
out of service for approximately 6 weeks and, due to heavy demand 
during the winter heating season, all engines were expected to be 
operable from October to April. Two additional cases show installation 
on multiple engines in short time periods. Southern California Gas 
Company completed testing of one engine in 1995 and installed 
precombustion chambers on six engines in its Mojave Desert operating 
area. The conversion of the first unit was completed in October 1995 
and the conversion of the sixth unit was completed in November 1996. 
The engines met the 2.0 g/bhp-hr standard set by the Mojave Air 
District. Furthermore, as cited in a case study in Vidor, Texas, six 
engines in the Beaumont/Port Arthur area were retrofitted in the summer 
of 1999.\58\
---------------------------------------------------------------------------

    \58\ See http://www.enginuityinc.com.
---------------------------------------------------------------------------

    As shown below, we also examined historic timeframes allowed by the 
Congress and various regulatory agencies to achieve compliance with 
NOX requirements following State/local rule adoption. These 
timeframes generally illustrate the successful implementation of past 
regulatory programs involving the installation of NOX 
controls.
    In the 1990 Amendments to the CAA, Congress added RACT requirements 
for major sources of NOX. All categories of major 
NOX sources in certain areas of the nation were required to 
install RACT as expeditiously as practicable or no later than May 31, 
1995. Thus, Congress allowed a maximum of 30 months from the SIP 
submittal deadline of November 15, 1992 for a much larger number of 
sources than affected by this rulemaking.
    Subsequent to the initial set of NOX RACT SIP revisions, 
we approved NOX RACT SIP submittals in some areas which had 
been exempt from the requirements. For example, in Dallas, SIP rules 
required RACT as expeditiously as practicable or 24 months from the 
State adoption date (rule adopted March 21, 1999). The State of Texas, 
on December 31, 1997, implemented a requirement for all major 
NOX sources in the Houston area to implement RACT; the State 
adopted a compliance date of November 15, 1999 for this program (22.5 
months). In a recent case, the State of Louisiana allowed up to a 3-
year period in Baton Rouge, coinciding with their attainment deadline.
    For engines subject to RACT limits, the California Air Resources 
Board guidance document on IC engines recommends final compliance 
within 2 years of district rule adoption.\59\ The guidance states that 
this time period should be sufficient to evaluate control options, 
place purchase orders, install equipment, and perform compliance 
verification testing. The Sacramento Air District in California 
required compliance within 2 years of rule adoption (June 1995).
---------------------------------------------------------------------------

    \59\ ``Determination of RACT and BARCT for Stationary Spark-
Ignited Internal Combustion Engines,'' California Air Resources 
Board, November 2001, pg. IV-15. (Docket No. OAR-2001-0008, Item No. 
XII-K-71.)
---------------------------------------------------------------------------

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

[[Page 21636]]

II.B.2.c of this final rule) to consider exempting pollution control 
projects from certain permitting requirements. Further, by moving the 
compliance date to at least 24 months after the SIP submittal date, we 
believe that the time needed to revise permits will not adversely 
affect the compliance schedule.
    Further, the CAA contains an overarching principle that downwind 
areas attain the ozone NAAQS ``as expeditiously as practicable.'' 
[Sections 191(a), 172(a)]. The emissions reductions from today's 
rulemaking reflect the emissions reductions mandated under the 
NOX SIP Call in order to prevent significant contribution to 
nonattainment in downwind States. Thus, we are setting an 
implementation date that will assure that the downwind States realize 
the air quality benefits of NOX reductions in order to 
achieve attainment or reasonable further progress toward attainment (63 
FR 57449-50).
    Although we provided a compliance date of 1,309 days for Phase I 
sources from the SIP submittal date, we do not believe that a similar 
compliance period is needed for the sources affected by today's 
rulemaking. This is because today's rulemaking affects a smaller subset 
of sources than Phase I sources, and these sources have been aware of 
the applicability of the NOX SIP Call since 1998. In 
addition, as discussed earlier, States are free to choose which sources 
to regulate in compliance with the NOX SIP Call 
requirements. Also, some States have already adopted SIPs that meet the 
full NOX SIP Call requirements.
    In summary, several factors described above will serve to minimize 
the number of large IC engines that would need to be scheduled for LEC 
retrofit. Further, companies that phase-in compliance activities over 
several years would also reduce the number of IC engines needing LEC 
retrofit per year. It is important to note that RACT experience shows 
that companies can install LEC retrofit over a 2-year timeframe, even 
where multiple engines are located at the same compressor station. In 
recent RACT compliance time decisions, State/local regulatory agencies 
generally specified 24-month periods to install controls. The Congress 
in its 1990 CAA Amendments allowed a maximum of 30 months for all major 
NOX sources across the nation to install RACT; this was a 
much larger task than installation of controls at IC engines in certain 
States. As a result, we believe that a 2-year period after the SIP 
submittal due date is adequate for the installation of controls.
    Further, because the NOX SIP Call is directed at 
emissions during the ozone season, we believe that the initial month 
where compliance is required should occur during the ozone season. 
Therefore, the compliance date is May 1, 2007 (or, if later, the date 
on which the source commences operation).
3. What Compliance Date Are We Finalizing for Georgia and Missouri?
    For all sources in Georgia and Missouri, we proposed a compliance 
date of May 1, 2005 (or, if later, the date on which the source 
commences operation). This compliance date was based on a proposed SIP 
submittal deadline of April 1, 2003 and would have provided sources 25 
months after SIP submittal to install controls. Based on the April 1, 
2005 SIP submittal deadline being finalized in today's final rule, 
providing sources with 25 months to install controls would result in a 
compliance deadline of May 1, 2007. Because this would be after the 
2006 ozone season, we are finalizing a compliance deadline of May 1, 
2007 (or, if later, the date on which the source commences operation). 
As we explained in the NOX SIP Call, we believe a 25-month 
compliance timeframe is reasonable given the amount of controls that 
need to be installed. If Missouri and/or Georgia elect to control large 
EGUs under a trading program, we project that the most time-consuming 
control installation will require installation of two SCRs and one 
SNCR. We also project that this can be done in 25 months (67 FR 8395).
    Several commenters suggested that a May 1, 2005 compliance date was 
reasonable for Georgia and Missouri if the rule were finalized in time 
to give States 1 year to develop a regulation and SIPs were due by 
April 1, 2003. One commenter added that many EGUs will be installing 
controls before 2005 in order to comply with a State ozone attainment 
plan. We agree that the proposed compliance deadline was reasonable 
when it was proposed. However, we are adopting a May 1, 2007 compliance 
deadline to take into account the delay in finalizing today's rule.
    One commenter suggested that providing units in Georgia and 
Missouri 25 months to comply was not enough time. This commenter 
provided documentation from an engineering firm suggesting that it 
would take at least 36 months to install SCR on one unit. The commenter 
further asserted that it would take even longer to install SCR on two 
units at a single plant and suggested that Missouri sources be given at 
least 43 months to install controls. We disagree with this commenter. 
Many SCR projects have been completed in significantly less time. For 
instance, a SCR was installed on the AES Somerset Plant in New York in 
9 months from contract award to completion. Reliant Energy completed 
construction of two SCRs on two 900 MW units at their Keystone Plant in 
Pennsylvania in 46 weeks. Even assuming that the engineering and 
permitting took a year, this job was completed in less than 24 months. 
It should also be noted that this job was completed in 2003. This was 
part of the peak construction period for SCRs under Phase I of the 
NOX SIP Call. Projects in Georgia and Missouri, being 
constructed after the bulk of the SCRs for the NOX SIP Call 
have been installed, should have much less competition for resources. 
The commenter provided no explanation of why this project should take 
so long when so many other projects have been completed in less time. 
Furthermore, the NOX SIP Call provides Missouri with CSP 
allowances that Missouri may use to address situations when 
installation cannot be completely finished by the compliance date. It 
should also be noted that while we believe that the SCRs can be 
installed within 25 months, if Missouri completes its SIP by December 
31, 2005, they will actually have 29 months to install the SCRs. This 
assumes that the company does not begin any work on the SCRs until 
after the SIP is finalized. Since the company should have a strong 
indication as to whether they will need to install the SCRs before the 
SIP is completed, they will actually have more than 29 months to 
install the SCRs.

L. What Action Are We Taking on Wisconsin?

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

[[Page 21637]]

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, 213 F.3d at 
681.
    We agree that additional modeling would be necessary in order to 
find that Wisconsin significantly contributes to downwind 1-hour 
nonattainment in any other State and to include Wisconsin in the 
NOX SIP Call at this time. We do not currently have the 
modeling necessary to take such action, therefore, we are excluding the 
entire State of Wisconsin from the requirements of the 1-hour basis of 
the NOX SIP Call to conform to the Court's decision. In 
addition, we received only one comment on excluding Wisconsin from the 
NOX SIP Call and it supported our proposal to do so.
    We are not, however, determining that Wisconsin's emissions do not 
contribute significantly to nonattainment downwind. We have not 
completed the additional modeling analysis for the States that are part 
of the OTAG region but were not included in the final NOX 
SIP Call. Although we stayed the 8-hour basis of the NOX SIP 
Call Rule on September 18, 2000 (65 FR 56245), we are in the process of 
evaluating lifting the stay. Today's action to exclude Wisconsin from 
the 1-hour basis of the NOX SIP Call does not address 
whether Wisconsin should remain subject to the 8-hour basis of the 
NOX SIP Call. We will address that issue at the time we lift 
the stay as it applies to Wisconsin.

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

    As noted above, the revisions to the NOX SIP Call in 
today's action respond to the Court's decision in Michigan. The Court's 
decision and today's action concern issues arising under only the 1-
hour ozone NAAQS, and not the 8-hour ozone NAAQS. Accordingly, none of 
the actions finalized today--the definitions of EGU and non-EGU and the 
control requirements for IC engines, and implications for the State 
budgets; the SIP submission dates; compliance dates; the revised 
emissions budgets for Alabama, Georgia, Michigan, and Missouri; and the 
exclusion of Wisconsin--have any effect on any requirements of the 
NOX SIP Call on States under the 8-hour ozone NAAQS. Because 
of the litigation concerning the 8-hour ozone NAAQS, we stayed all of 
the requirements of the NOX SIP Call under the 8-hour ozone 
NAAQS, ranging from the SIP submission dates to the control 
requirements (65 FR 56245, September 18, 2000). Since then, the Supreme 
Court has held that the CAA authorizes EPA to revise the ozone NAAQS. 
Whitman v. American Trucking Ass'ns., 121 S. Ct. 903 (2001).
    At this time, we are evaluating the process for lifting the 8-hour 
stay. Originally, the NOX SIP Call requirements under the 1-
hour and 8-hour standards were the same. As a result of court actions, 
some parts of the 1-hour NOX SIP Call are being modified in 
this rule.
    For the Interstate Air Quality Rule (IAQR), which we proposed on 
January 30, 2004 (FR 69 4566), we reassessed the 8-hour transport 
following the approach used in the NOX SIP Call, but using 
an updated model and updated inputs that reflect current requirements, 
including the NOX SIP Call. The IAQR proposes additional 
control requirements for 2010 and 2015 to address the transport that 
remains in later years after the implementation of the NOX 
SIP Call. For a more detailed discussion of how the NOX SIP 
Call and the IAQR would interact, see the IAQR proposal.

N. What Modifications Are Being Made to Parts 51, 78, and 97?

    Today's action makes certain modifications to 40 CFR Part 51, the 
implementing regulations for the NOX SIP Call Rule, that 
were promulgated on October 28, 1998. These modifications, which 
include clarifications, definitions, and minor changes, are being made 
in response to the various court decisions on the NOX SIP 
Call, (Michigan v. EPA, 213 F. 3d 663 (DC Cir. 2000), cert denied, 121 
S. Ct. 1225 (2001)), the NOX SIP Call Technical Amendments 
(Appalachian Power v. EPA, 251 F. 3d 1026 (DC Cir. 2001)), and the 
Section 126 Rule (Appalachian Power v. EPA, 249 F. 3d 1042 (DC Cir. 
2001)).
    In response to the court decision in Michigan, the Agency divided 
the NOX SIP Call into two phases (Phase I and Phase II), 
thereby enabling the Agency to proceed with those portions of the 
NOX SIP Call that were upheld by the Court. Phase II 
addresses issues that were either remanded or remanded and vacated by 
the Court. As a result of the various court challenges and decisions 
referenced above, most of the applicable dates are no longer correct. 
States are now complying or have complied with dates either set by the 
Court or dates triggered by the court decisions. Today's action 
modifies the applicable provisions to reflect the revised applicable 
dates. In most instances, today's revisions do not include specific 
dates but rather specify a timeframe, either during the first or second 
ozone season, in relation to when the Phase I and Phase II sources are 
subject to control measures and other applicable requirements. New 
Sec.  51.121(a)(3) defines ``Phase I'' and ``Phase II.''
    Section 51.121(b)(1)(ii) is modified to specify the new dates for 
implementation of required control measures under Phase I and Phase II. 
All subsequent sections are modified to align with these new 
implementation dates. Section 51.121(b)(2)(ii)(B) is modified to 
reflect the period during which States may accumulate early reduction 
credits that may be subsequently utilized for compliance with the 
NOX SIP Call requirements. Section 51.121(b)(2)(ii)(C) is 
also modified to specify the new period during which States may bank 
emissions credits. Section 51.121(b)(2)(ii)(D) is modified to reflect 
the new period when banked allowances will not be affected by the 
limitation on the use of banked emissions reductions credits or 
emissions allowances or the flow control provisions. Compliance 
supplement pool credits are considered banked at the start of the 
second year of the NOX SIP Call program and are therefore, 
subject to the flow control provisions.
    Section 51.121(b)(2)(ii)(E) is modified to reflect the new period 
when flow control provisions will be triggered. The compliance date for 
the initial NOX SIP Call program was May 1, 2003, and the 
flow control provisions were to begin in the second year of the 
program, i.e., 2004. However, in Michigan, the Court ruled that May 31, 
2004, rather than May 1, 2003, is the compliance date for sources now 
covered under Phase I. Since then, we have implemented the new flow 
control dates through notice and comment rulemakings for approval of 
State NOX SIP Call SIPs, except for Georgia and Missouri. 
Flow control issues for Georgia and Missouri will be addressed in the 
context of reviewing their SIPs, as discussed in section I.1. of this 
rule.
    Section 51.121(c), which specifies the States subject to the 
NOX SIP Call with respect to the 1-hour ozone NAAQS, is 
modified by adding sections

[[Page 21638]]

51.121(c)(1) and (c)(2). New Sec.  51.121(c)(1) specifies States that 
all areas of the State are subject to the NOX SIP Call, and 
Sec.  51.121(c)(2) specifies those States that only areas of the State 
that lie within the fine grid portions are subject to the 
NOX SIP Call. Section 51.121(c)(2) also defines the fine 
grid for purposes of the NOX SIP Call.
    Section 51.121(d) is modified to reflect dates by which all the 
States subject to the NOX SIP Call must submit required SIP 
revisions to EPA for Phase I and Phase II. This revision reflects the 
Phase I SIP submittal date of October 30, 2000, which was set by the 
Court in Michigan. Phase II SIPs are now due by April 1, 2005.
    Section 51.121(e)(2) is renumbered and modified to reflect the 
revised NOX budgets for each State. Section 51.121(e)(2)(i) 
contains the modified table reflecting changes to the State-by-State 
NOX budgets. New Sec.  51.121(e)(2)(ii) (A)-(D) specifies 
counties, which lie within the fine grid, in the States of Alabama, 
Georgia, Michigan, and Missouri that are subject to the NOX 
SIP Call requirements.
    Section 51.121(e)(3) is being renumbered as Sec.  51.121(e)(4). A 
new Sec.  51.121(e)(3)(i) is added to define the portion of the 
NOX budget that may be included in a Phase II SIP submission 
for each State.
    In Sec.  51.121(e)(4)(i) the period within which sources may use 
CSP credits to demonstrate compliance with the NOX SIP Call 
requirements is modified. This revision is consistent with the original 
2-year window specified in the NOX SIP Call (63 FR 57428-
57430, October 27, 1998). Allowances from the CSP must be used by 
September 30, 2005 and September 20, 2008, for Phase I and Phase II 
sources, respectively. Section 51.121(e)(4)(ii) is modified by revising 
the date after which sources may not use CSP credits. Section 
51.121(e)(4)(iii) is modified to show the revised State-by-State CSP 
amounts. Section 51.121(e)(4)(iv)(A) is modified by revising the period 
during which sources must implement emissions reductions to receive CSP 
credits. Section 51.121(e)(4)(iv)(A)(1) is modified by revising the 
date by which States are to complete issuance of CSP credits to sources 
covered by the NOX SIP Call. Section 51.121(e)(4)(iv)(A)(3) 
is modified by revising the period during which emissions reductions 
must occur for sources to qualify for CSP credits. Section 
51.121(e)(4)(iv)(B) is modified by revising the former control 
implementation date to reflect the new control implementation dates. 
Section 51.121(e)(4)(iv)(B)(1) is modified to reflect new dates by 
which States must initiate the issuance of CSP credits. Section 
51.121(e)(4)(iv)(B)(2) is modified by revising the date by which the 
States are to complete issuance of CSP credits. Sections 
51.121(e)(4)(iv)(B)(3)(i) and (ii) are modified to reflect the new 
control implementation dates.
    Section 51.121(e)(4) is renumbered as section 51.121(e)(5).
    Sections 51.122 (g)(1) and (2) are modified to reflect the 
beginning and frequency of annual and triennial emissions reporting by 
States. A new Table is inserted. Section 51.122 (h)(1) is modified to 
specify the address for submission of the required reports.
    Today's action also finalizes modifications to 40 CFR parts 78 and 
97 that were proposed on June 13, 2001. The modifications to part 78 
were proposed so that affected sources under the Federal NOX 
Budget Trading Program would have the same right of administrative 
appeal as affected sources under the Acid Rain Program. We received no 
comments on the revisions to part 78. The proposed revisions to part 97 
were made in order to align monitoring and reporting requirements with 
modification to part 75 made after the promulgation of part 97 and to 
correct certain grammatical and technical errors. We received two 
comments, one supporting a proposed revision to part 97 and the other 
suggesting a change that was addressed in the June 12, 2002 final 
revisions to part 75 (in Sec.  75.19).
    We are finalizing the proposed modifications to parts 78 and 97 as 
proposed, with only three exceptions of any significance.\60\ The final 
revisions to Sec.  97.61(b) differ from the proposed revisions in that 
the final revisions use language consistent with language in the 
analogous provision in Sec.  96.61(b) of the model rule for the 
NOX Budget Trading Program under the NOX SIP 
Call. In particular, the final revisions refer to ``the control period 
to which the NOX allowance transfer deadline applies,'' 
rather than referencing ``the control period in the same year as the 
NOX allowance transfer deadline.'' We believe that the 
language in the final revisions to Sec.  97.61(b) is clearer and more 
accurate than the language in the proposed revisions, as well as being 
analogous to the language in Sec.  96.61(b).
---------------------------------------------------------------------------

    \60\ In addition, the final revisions correct, without any 
substantive changes, a few minor, technical errors in the proposed 
revisions or that were inadvertently left out of the proposed 
revisions.
---------------------------------------------------------------------------

    Further, the final revisions to Sec.  97.70(b)(5) and (6) differ 
from the proposed revisions in that the final revisions use language 
consistent with language in the analogous provision in Sec.  75.4(e) of 
the Acid Rain Program emission monitoring regulations. In particular, 
the final revisions add, to the language ``a new stack or flue,'' a 
reference to new ``add-on NOX emission controls.'' As a 
result, Sec.  97.70(b)(5) and (6) contain the same references to new 
stacks, flues, or add-on NOX emission controls as Sec.  
75.4(e). Similarly, the final revisions to Sec.  97.71(c) differ from 
the proposed revisions in that the final revisions use language 
consistent with language in the analogous provision in Sec.  
75.20(h)(3) of the Acid Rain Program emission monitoring regulations. 
In particular, the final revisions [similar to Sec.  75.20(h)(3)] 
provide that provisional certification status for the low mass emission 
excepted methodology is tied to receipt of a ``complete'' certification 
application.

III. Statutory and Executive Order Reviews

A. Executive Order 12866: Regulatory Planning and Review

    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 action, which responds to the court decisions in Michigan v. 
EPA, 213 F.3d 663 (DC Cir. 2000) (NOX SIP Call); Appalachian 
Power v. EPA, 249 F.3d 1032 (DC Cir. 2001) (Section 126 Rule), and 
Appalachian Power v. EPA, 251 F.3d 1026 (DC 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.

[[Page 21639]]

Because 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 OAR-2001-0008)] 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, for IC engines, 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) and 
``Stationary Reciprocating Internal Combustion Engines: Updated 
Information on NOX Emissions and Control Techniques,'' 
(September 1, 2000). 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. These documents are available 
for public inspection in Docket OAR-2001-0008 which is listed in the 
ADDRESSES section of this preamble. Although the original RIA estimated 
costs for controls on IC engines of $100 million, we now estimate a 
cost of less than $33 million due to fewer sources affected, lower cost 
per ton, and a lower average control level ($1990, ozone season). In 
addition, we now estimate the costs for controls in Georgia and 
Missouri to be approximately $136 million. Due to today's action to 
remove Wisconsin and portions of Alabama, Georgia, Michigan, and 
Missouri from the 1998 NOX SIP Call rule, the costs 
estimated in the 1998 RIA are lowered by about $146 million).

B. 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.

C. Regulatory Flexibility Act (RFA)

    The EPA has determined that it is not necessary to prepare a 
regulatory flexibility analysis in connection with this final rule.
    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 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 final rule on 
small entities, EPA has concluded that this action will not have a 
significant economic impact on a substantial number of small entities. 
This final rule will not impose any requirements on small entities. 
This final rule responds to the court decisions in Michigan v. EPA, 213 
F.3d 663, Appalachian Power v. EPA, 249 F.3d 1032 (DC Cir. 2001), and 
Appalachian Power v. EPA, 251 F.3d 1026 (DC 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.

D. 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 Section 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.

E. 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 action addressing the NOX SIP Call and Section 126 
Rules does not have federalism implications. It will not

[[Page 21640]]

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 NOX 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 NOX 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 DC 
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 (DC Cir. 2000) 
(NOX SIP Call). Today, EPA is finalizing 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 (DC Cir. 2001) (NOX 
SIP Call Technical Amendments).
    With respect to the action concerning the definition of EGU and the 
level of control for IC engines, action revising the emission budgets 
for Georgia, Missouri, Alabama, and Michigan, and the SIP submission 
and source compliance dates, EPA's action 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 NOX SIP Call Rule, which remains in place for 
19 States (including Alabama and Michigan) and the District of 
Columbia. Moreover, no aspect of this 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 NOX SIP Call Rule to 
choose the control requirements necessary to address the transported 
emissions identified by EPA in the NOX SIP Call Rule.
    As provided in the final action promulgating the NOX SIP 
Call Rule and the Technical Amendments, the NOX SIP Call 
Rule 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 (DC 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).

F. 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 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 today's action. 
Thus, Executive Order 13175 does not apply to this rule.

G. Executive Order 13045: Protection of Children From Environmental 
Health 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.

H. Executive Order 13211: Actions That Significantly Affect Energy 
Supply, Distribution, or Use

    This summary of the energy impact analysis report dated October 2, 
2001 (Docket No. OAR-2001-0008, Item No. XII-L-06] estimates the energy 
impacts associated with the Phase II portion of the NOX SIP 
Call, in accordance with Executive Order 13211. It covers all large 
EGUs that do not participate in the Acid Rain Trading Program and large 
IC engines 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 IC engines) in the fine grid portions of Georgia and 
Missouri. This analysis also considered impacts on sources in only the 
fine grid portions of Michigan and Alabama. We 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 the analysis, we 
identified three relevant energy effects that occur during normal 
operation of these devices: increased energy demands required by 
certain 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

[[Page 21641]]

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.\61\ With respect to energy sources, the 
application of LEC technology to natural gas-driven IC engines amounts 
to a savings of about 4,000 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.
---------------------------------------------------------------------------

    \61\ 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 Call 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 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.
    We received four comments on this administrative requirement as 
summarized below (XII-D-07, TX Gas Transmission Corp.; XII-D-09, INGAA; 
XII-D-10, El Paso Corp.; XII-F-12, NiSource, Inc.).
    Comment: Executive Order 13211 requires us to analyze the effect of 
its regulations on the Nation's energy supply, distribution and use. 
Commenters state that (1) We failed to analyze, or even recognize, its 
deadline's potential effect on the United States' natural gas 
transmission system (XII-F-12), (2) the proposal's impractical 
compliance deadline could compromise much of the Nation's gas 
transmission and storage system, yet there has been no analysis of this 
issue, (3) EPA must provide a compliance period that is adequate to 
avoid these problems, and (4) the Agency must conduct a study that 
demonstrates (after notice and opportunity for comment) that it has 
fully considered all of the impacts on energy supply and distribution. 
(p. 12 of comment XII-D-09 and p. 13 of comment XII-D-10.)
    Response: We disagree with the comment that we failed to analyze 
the effect of this rule on the Nation's energy supply, distribution and 
use. In accordance with Executive Order 13211, we completed an energy 
impact analysis of this rule, on October 2, 2001. The analysis 
indicated minimal effects, less than 0.5 percent nationally, on both 
energy supply, distribution and demand, including natural gas.
    We note that the more prevalent LEC retrofit, which has been in use 
for almost 20 years, is the screw-in precombustion chamber.\62\ This 
kind of retrofit is both less costly and time-consuming than other 
kinds of LEC retrofit. For example, Columbia Gas Transmission 
Corporation, using screw-in precombustion chambers, retrofit two IC 
engines at its Bedford County, Pennsylvania, facility within 3 
days.\63\ We have also found that most, if not all, natural gas 
pipeline stations are equipped with multiple IC engines and that not 
all engines are operated at the same time. Therefore, we believe that 
LEC retrofits can be phased-in making it less likely for an entire 
station to go offline for a LEC retrofit. Thus, because a phased-in 
approach is feasible, we believe that engine stations can continue 
operating close to their standard level thereby avoiding service 
interruptions. We also note that the December 1998 Gas Research 
Institute report concluded that ``installation of the [LEC] retrofit 
kit is not expected to impact the normal maintenance interval.''\64\ 
The energy impact analysis also indicated that IC engines retrofit with 
LEC will experience, on average, an energy savings of half a million 
BTUs per hour per engine, and therefore savings in operating costs.
---------------------------------------------------------------------------

    \62\ Stationary Reciprocating Internal Combustion Engines 
Updated Information on NOX Emissions and Control 
Techniques, Revised Final Report, prepared by Ec/R, Inc. for EPA, p. 
4-2, September 1, 2000, available on the Internet at http://www.epa.gov/ttn/naaqs/ozone/rto/fip/data/rfic_engine.pdf.
    \63\ Found in reprint of article in ``American Gas & Oil 
Reporter,'' May 1998, available on the Internet at http://www.dieselsupply.com/dscartic.htm.
    \64\ ``NOX Control for Two-Cycle Pipeline 
Reciprocating Engines,'' p. 4-11, December 1998.
---------------------------------------------------------------------------

    The comment that the 11-month compliance deadline could compromise 
the nation's gas transmission and storage system is no longer an issue 
because we are allowing more than 24 months from SIP submittal date for 
implementation of controls. Our response to this comment is fully 
discussed in section II.K.2 of this rule, ``What Compliance Date Are We 
Finalizing for IC Engines and What is the Technical Feasibility of This 
Date?''
    With the improvements in ease of LEC retrofits that include 
scheduling retrofits during maintenance cycles, the adequate time we 
believe exists for implementation, and the flexibility granted to 
States to meet their NOX budgets, we do not believe the 
concerns expressed about effects on natural gas transmission from 
compliance with the Phase II NOX SIP Call rule are 
warranted.

I. National Technology Transfer Advancement Act

    The National Technology Transfer Advancement Act of 1997 does not 
apply because today's 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 final 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.

J. Executive Order 12898: Federal Actions To Address Environmental 
Justice in Minority Populations and Low-Income Populations

    This action does not involve special consideration of environmental 
justice related issues as required by Executive

[[Page 21642]]

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

K. Congressional Review Act

    The Congressional Review Act, 5 U.S.C. 801 et seq., as added by the 
Small Business Regulatory Enforcement Fairness Act of 1996, generally 
provides that before a rule may take effect, the agency promulgating 
the rule must submit a rule report, which includes a copy of the rule, 
to each House of the Congress and to the Comptroller General of the 
United States. The EPA will submit a report containing this rule and 
other required information to the U.S. Senate, the U.S. House of 
Representatives, and the Comptroller General of the United States prior 
to publication of the rule in the Federal Register. A ``major rule'' 
cannot take effect until 60 days after it is published in the Federal 
Register. This action is a ``major rule'' as defined by 5 U.S.C. Sec.  
804(2). This rule will be effective June 21, 2004.

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 78

    Air pollution control, Nitrogen oxides, Ozone, Acid Rain Program, 
Trading budget, Compliance supplement pool.

40 CFR Part 97

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

    Dated: April 1, 2004.
Michael O. Leavitt,
Administrator.


0
For the reasons set out in the preamble, title 40 chapter of the Code 
of Federal Regulations is amended as follows:

PART 51--[Amended]

0
1. The Authority citation for part 51 continues to read as follows:

    Authority: 23 U.S.C. 101; 42 U.S.C. 7401-7671q.


0
2. Section 51.121 is amended:
0
a. By adding paragraph (a)(3).
0
b. By revising paragraphs (b)(1)(ii), (b)(2)(ii)(B), (b)(2)(ii)(C), 
(b)(2)(ii)(D), and (b)(2)(ii)(E) introductory text.
0
c. By revising paragraph (c).
0
d. By revising paragraph (d)(1).
0
e. By revising paragraphs (e)(1) and (e)(2).
0
f. By redesignating paragraphs (e)(3) and (e)(4) as (e)(4) and (e)(5).
0
g. By adding a new paragraph (e)(3).
0
h. By revising newly designated paragraphs (e)(4)(i), (e)(4)(ii), 
(e)(4)(iii), (e)(4)(iv)(A) introductory text, (e)(4)(iv)(A)(1), 
(e)(4)(iv)(A)(3), (e)(4)(iv)(B) introductory text, (e)(4)(iv)(B)(1), 
(e)(4)(iv)(B)(2), (e)(4)(iv)(B)(3)(i), (e)(4)(iv)(B)(3)(ii), 
(e)(4)(iv)(B)(3)(iii).
    The revisions and additions read as follows:


Sec.  51.121  Findings and requirements for submission of State 
implementation plan revisions relating to emissions of oxides of 
nitrogen.

    (a) * * *
    (3)(i) For purposes of this section, the term ``Phase I SIP 
Submission'' means those SIP revisions submitted by States on or before 
October 30, 2000 in compliance with paragraph (b)(1)(ii) of this 
section. A State's Phase I SIP submission may include portions of the 
NOX budget, under paragraph (e)(3) of this section, that a 
State is required to include in a Phase II SIP submission.
    (ii) For purposes of this section, the term ``Phase II SIP 
Submission'' means those SIP revisions that must be submitted by a 
State in compliance with paragraph (b)(1)(ii) of this section and which 
includes portions of the NOX budget under paragraph (e)(3) 
of this section.
    (b) * * *
    (1) * * *
    (ii) Requires full implementation of all such control measures by 
no later than May 31, 2004 for the sources covered by a Phase I SIP 
submission and May 1, 2007 for the sources covered by a Phase II SIP 
submission.
    (2) * * *
    (ii) * * *
    (B) Emissions reductions occurring prior to the first year in which 
any sources covered by Phase I or Phase II SIP submission are subject 
to control measures under paragraph (b)(1)(i) of this section may be 
used by a source to demonstrate compliance with the SIP revision for 
the first and second ozone seasons in which any sources covered by a 
Phase I or Phase II SIP submission are subject to such control 
measures, provided the SIPs provisions regarding such use comply with 
the requirements of paragraph (e)(4) of this section.
    (C) Emissions reductions credits or emissions allowances held by a 
source or other person following the first ozone season in which any 
sources covered by a Phase I or Phase II SIP submission are subject to 
control measures under paragraph (b)(1)(i) of this section or any ozone 
season thereafter that are not required to demonstrate compliance with 
the SIP for the relevant ozone season may be banked and used to 
demonstrate compliance with the SIP in a subsequent ozone season.
    (D) Early reductions created according to the provisions in 
paragraph (b)(2)(ii)(B) of this section and used in the first ozone 
season in which any sources covered by Phase I or Phase II submissions 
are subject to the control measures under paragraph (b)(1)(i) of this 
section are not subject to the flow control provisions set forth in 
paragraph (b)(2)(ii)(E) of this section.
    (E) Starting with the second ozone season in which any sources 
covered by a Phase I or Phase II SIP submission are subject to control 
measures under paragraph (b)(1)(i) of this section, the SIP shall 
include provisions to limit the use of banked emissions reductions 
credits or emissions allowances beyond a predetermined amount as 
calculated by one of the following approaches:
* * * * *
    (c) The following jurisdictions (hereinafter referred to as 
``States'') are subject to the requirement of this section:
    (1) With respect to the 1-hour ozone NAAQS: Connecticut, Delaware, 
Illinois, Indiana, Kentucky, Maryland, Massachusetts, New Jersey, New 
York, North Carolina, Ohio, Pennsylvania, Rhode Island, South Carolina, 
Tennessee, Virginia, West Virginia, and the District of Columbia.
    (2) With respect to the 1-hour ozone NAAQS, the portions of 
Missouri, Michigan, Alabama, and Georgia within the fine grid of the 
OTAG modeling domain. The fine grid is the area encompassed by a box 
with the following geographic coordinates: Southwest Corner, 92 degrees 
West longitude and 32 degrees North latitude; and Northeast Corner, 
69.5 degrees West longitude and 44 degrees North latitude.
    (d) * * *
    (1) The SIP submissions required under paragraph (a) of this 
section must be submitted to EPA by no later than

[[Page 21643]]

October 30, 2000 for Phase I SIP submissions and no later than April 1, 
2005 for Phase II SIP submissions.
* * * * *
    (e)(1) Except as provided in paragraph (e)(2)(ii) of this section, 
the NOX budget for a State listed in paragraph (c) of this 
section is defined as the total amount of NOX emissions from 
all sources in that State, as indicated in paragraph (e)(2)(i) of this 
section with respect to that State, which the State must demonstrate 
that it will not exceed in the 2007 ozone season pursuant to paragraph 
(g)(1) of this section.
    (2)(i) The State-by-State amounts of the NOX budget, 
expressed in tons, are as follows:

------------------------------------------------------------------------
                      State                          Final budget   Budget
------------------------------------------------------------------ --------
Alabama..........................................          119,827
Connecticut......................................           42,850
Delaware.........................................           22,862
District of Columbia.............................            6,657
Georgia..........................................          150,656
Illinois.........................................          271,091
Indiana..........................................          230,381
Kentucky.........................................          162,519
Maryland.........................................           81,947
Massachusetts....................................           84,848
Michigan.........................................          190,908
Missouri.........................................           61,406
New Jersey.......................................           96,876
New York.........................................          240,322
North Carolina...................................          165,306
Ohio.............................................          249,541
Pennsylvania.....................................          257,928
Rhode Island.....................................            9,378
South Carolina...................................          123,496
Tennessee........................................          198,286
Virginia.........................................          180,521
West Virginia....................................           83,921
                                                  ------------------
  Total..........................................       $3,031,527
------------------------------------------------------------------------

    (ii) (A) For purposes of paragraph (e)(2)(i) of this section, in 
the case of each State listed in paragraphs (e)(2)(ii)(B) through (E) 
of this section, the NOX budget is defined as the total 
amount of NOX emissions from all sources in the specified 
counties in that State, as indicated in paragraph (e)(2)(i) of this 
section with respect to the State, which the State must demonstrate 
that it will not exceed in the 2007 ozone season pursuant to paragraph 
(g)(1) of this section.
    (B) In the case of Alabama, the counties are: Autauga, Bibb, 
Blount, Calhoun, Chambers, Cherokee, Chilton, Clay, Cleburne, Colbert, 
Coosa, Cullman, Dallas, De Kalb, Elmore, Etowah, Fayette, Franklin, 
Greene, Hale, Jackson, Jefferson, Lamar, Lauderdale, Lawrence, Lee, 
Limestone, Macon, Madison, Marion, Marshall, Morgan, Perry, Pickens, 
Randolph, Russell, St. Clair, Shelby, Sumter, Talladega, Tallapoosa, 
Tuscaloosa, Walker, and Winston.
    (C) In the case of Georgia, the counties are: Baldwin, Banks, 
Barrow, Bartow, Bibb, Bleckley, Bulloch, Burke, Butts, Candler, 
Carroll, Catoosa, Chattahoochee, Chattooga, Cherokee, Clarke, Clayton, 
Cobb, Columbia, Coweta, Crawford, Dade, Dawson, De Kalb, Dooly, 
Douglas, Effingham, Elbert, Emanuel, Evans, Fannin, Fayette, Floyd, 
Forsyth, Franklin, Fulton, Gilmer, Glascock, Gordon, Greene, Gwinnett, 
Habersham, Hall, Hancock, Haralson, Harris, Hart, Heard, Henry, 
Houston, Jackson, Jasper, Jefferson, Jenkins, Johnson, Jones, Lamar, 
Laurens, Lincoln, Lumpkin, McDuffie, Macon, Madison, Marion, 
Meriwether, Monroe, Morgan, Murray, Muscogee, Newton, Oconee, 
Oglethorpe, Paulding, Peach, Pickens, Pike, Polk, Pulaski, Putnam, 
Rabun, Richmond, Rockdale, Schley, Screven, Spalding, Stephens, Talbot, 
Taliaferro, Taylor, Towns, Treutlen, Troup, Twiggs, Union, Upson, 
Walker, Walton, Warren, Washington, White, Whitfield, Wilkes, and 
Wilkinson.
    (D) In the case of Michigan, the counties are: Allegan, Barry, Bay, 
Berrien, Branch, Calhoun, Cass, Clinton, Eaton, Genesee, Gratiot, 
Hillsdale, Ingham, Ionia, Isabella, Jackson, Kalamazoo, Kent, Lapeer, 
Lenawee, Livingston, Macomb, Mecosta, Midland, Monroe, Montcalm, 
Muskegon, Newaygo, Oakland, Oceana, Ottawa, Saginaw, St. Clair, St. 
Joseph, Sanilac, Shiawassee, Tuscola, Van Buren, Washtenaw, and Wayne.
    (E) In the case of Missouri, the counties are: Bollinger, Butler, 
Cape Girardeau, Carter, Clark, Crawford, Dent, Dunklin, Franklin, 
Gasconade, Iron, Jefferson, Lewis, Lincoln, Madison, Marion, 
Mississippi, Montgomery, New Madrid, Oregon, Pemiscot, Perry, Pike, 
Ralls, Reynolds, Ripley, St. Charles, St. Genevieve, St. Francois, St. 
Louis, St. Louis City, Scott, Shannon, Stoddard, Warren, Washington, 
and Wayne.
    (3) The State-by-State amounts of the portion of the NOX 
budget provided in paragraph (e)(1) of this section, expressed in tons, 
that the States may include in a Phase II SIP submission are as 
follows:

------------------------------------------------------------------------
                                                             Phase II
                         State                             incremental
                                                              budget
------------------------------------------------------------------------
Alabama................................................            4,968
Connecticut............................................               41
Delaware...............................................              660
District of Columbia...................................                1
Illinois...............................................            7,055
Indiana................................................            4,244
Kentucky...............................................            2,556
Maryland...............................................              780
Massachusetts..........................................            1,023
Michigan...............................................            1,033
New Jersey.............................................             -994
New York...............................................            1,659
North Carolina.........................................            6,026
Ohio...................................................            2,741
Pennsylvania...........................................           10,230
Rhode Island...........................................              192
South Carolina.........................................            4,260
Tennessee..............................................            2,877
Virginia...............................................            6,168
West Virginia..........................................            1,124
                                                        ----------------
    Total..............................................           56,644
------------------------------------------------------------------------

    (4)(i) Notwithstanding the State's obligation to comply with the 
budgets set forth in paragraph (e)(2) of this section, a SIP revision 
may allow sources required by the revision to implement NOX 
emission control measures to demonstrate compliance in the first and 
second ozone seasons in which any sources covered by a Phase I or Phase 
II SIP submission are subject to control measures under paragraph 
(b)(1)(i) of this section using credit issued from the State's 
compliance supplement pool, as set forth in paragraph (e)(4)(iii) of 
this section.
    (ii) A source may not use credit from the compliance supplement 
pool to demonstrate compliance after the second ozone season in which 
any sources are covered by a Phase I or Phase II SIP submission.
    (iii) The State-by-State amounts of the compliance supplement pool 
are as follows:

------------------------------------------------------------------------
                                                            Compliance
                         State                           supplement pool
                                                           (tons of NOX)
------------------------------------------------------------------------
Alabama................................................            8,962
Connecticut............................................              569
Delaware...............................................              168
District of Columbia...................................                0
Georgia................................................           10,728
Illinois...............................................           17,688
Indiana................................................           19,915
Kentucky...............................................           13,520
Maryland...............................................            3,882
Massachusetts..........................................              404
Michigan...............................................            9,907
Missouri...............................................            5,630
New Jersey.............................................            1,550
New York...............................................            2,764
North Carolina.........................................           10,737
Ohio...................................................           22,301
Pennsylvania...........................................           15,763
Rhode Island...........................................               15
South Carolina.........................................            5,344
Tennessee..............................................           10,565
Virginia...............................................            5,504
West Virginia..........................................           16,709
                                                        ----------------
  Total................................................          182,625
------------------------------------------------------------------------

    (iv) * * *

[[Page 21644]]

    (A) The State may issue some or all of the compliance supplement 
pool to sources that implement emissions reductions during the ozone 
season beyond all applicable requirements in the first ozone season in 
which any sources covered by a Phase I or Phase II SIP submission are 
subject to control measures under paragraph (b)(1)(i) of this section.
    (1) The State shall complete the issuance process by no later than 
the commencement of the first ozone season in which any sources covered 
by a Phase I or Phase II SIP submission are subject to control measures 
under paragraph (b)(1)(i) of this section.
* * * * *
    (3) The emissions reductions must be verified by the source as 
actually having occurred during an ozone season between September 30, 
1999 and the commencement of the first ozone season in which any 
sources covered by a Phase I or Phase II SIP submission are subject to 
control measures under paragraph (b)(1)(i) of this section.
* * * * *
    (B) The State may issue some or all of the compliance supplement 
pool to sources that demonstrate a need for an extension of the 
earliest date on which any sources covered by a Phase I or Phase II SIP 
submission are subject to control measures under paragraph (b)(1)(i) of 
this section according to the following provisions:
    (1) The State shall initiate the issuance process by the later date 
of September 30 before the first ozone season in which any sources 
covered by a Phase I or Phase II SIP submission are subject to control 
measures under paragraph (b)(1)(i) of this section or after the State 
issues credit according to the procedures in paragraph (e)(4)(iv)(A) of 
this section.
    (2) The State shall complete the issuance process by no later than 
the commencement of the first ozone season in which any sources covered 
by a Phase I or Phase II SIP submission are subject to control measures 
under paragraph (b)(1)(i) of this section.
    (3) * * *
    (i) For a source used to generate electricity, compliance with the 
SIP revision's applicable control measures by the commencement of the 
first ozone season in which any sources covered by a Phase I or Phase 
II SIP submission are subject to control measures under paragraph 
(b)(1)(i) of this section, would create undue risk for the reliability 
of the electricity supply. This demonstration must include a showing 
that it would not be feasible to import electricity from other 
electricity generation systems during the installation of control 
technologies necessary to comply with the SIP revision.
    (ii) For a source not used to generate electricity, compliance with 
the SIP revision's applicable control measures by the commencement of 
the first ozone season in which any sources covered by a Phase I or 
Phase II SIP submission are subject to control measures under paragraph 
(b)(1)(i) of this section would create undue risk for the source or its 
associated industry to a degree that is comparable to the risk 
described in paragraph (e)(4)(iv)(B)(3)(i) of this section.
    (iii) For a source subject to an approved SIP revision that allows 
for early reduction credits in accordance with paragraph (e)(4)(iv)(A) 
of this section, it was not possible for the source to comply with 
applicable control measures by generating early reduction credits or 
acquiring early reduction credits from other sources.
* * * * *

0
3. Section 51.122 is amended by:
0
a. revising paragraphs (g)(1), and (g)(2),
0
b. removing paragraph (g)(3) and redesignating paragraph (g)(4) as 
(g)(3),
0
c. revising paragraph (h)(1).
    The revisions read as follows:


Sec.  51.122  Emissions reporting requirements for SIP revisions 
relating to budgets for NOX emissions.

* * * * *
    (g) * * *
    (1) Data collection is to begin during the ozone season 1 year 
prior to the State's NOX SIP Call compliance date.
    (2) Reports are to be submitted according to paragraph (b) of this 
section and the schedule in Table 1. After 2008, trienniel reports are 
to be submitted every third year and annual reports are to be submitted 
each year that a trienniel report is not required.

                Table 1.--Schedule for Submitting Reports
------------------------------------------------------------------------
          Data collection year               Type of report  required
------------------------------------------------------------------------
2002...................................  Trienniel.
2003...................................  Annual.
2004...................................  Annual.
2005...................................  Trienniel.
2006...................................  Annual.
2007...................................  Year 2007 Report.
2008...................................  Trienniel.
------------------------------------------------------------------------

* * * * *
    (h) * * *
    (1) States are required to report emissions data in an electronic 
format to one of the locations listed in this paragraph (h). Several 
options are available for data reporting. States can obtain information 
on the current formats at the following Internet address: http://www.epa.gov/ttn/chief, by calling the EPA Info CHIEF help desk at (919) 
541-1000 or by sending an e-mail to [email protected]. Because 
electronic reporting technology continually changes, States are to 
contact the Emission Factor and Inventory Group (EFIG) for the latest 
specific formats.
* * * * *

PART 78--APPEAL PROCEDURES FOR ACID RAIN PROGRAM

0
1. The authority citation for part 78 is revised to read as follows:

    Authority: 42 U.S.C. 7401, 7403, 7410, 7426, 7601, and 7651, et 
seq.


0
2. Section 78.1 is amended in paragraph (a)(1) by removing the words 
``parts 72, 73, 74, 75, 76, and 77 of this chapter'' and adding in its 
place the words ``parts 72, 73, 74, 75, 76, or 77 of this chapter or 
part 97 of this chapter''; and adding a new paragraph (b)(6) to read as 
follows:


Sec.  78.1  Purpose and scope.

    (b) * * *
    (6) Under part 97 of this chapter:
    (i) The adjustment of the information in a compliance certification 
or other submission and the deduction or transfer of NOX 
allowances based on the information, as adjusted, under Sec.  97.31 of 
this chapter;
    (ii) The decision on the allocation of NOX allowances to 
a NOX Budget unit under Sec.  97.41(b), (c), (d), or (e) of 
this chapter;
    (iii) The decision on the allocation of NOX allowances 
to a NOX Budget unit from the compliance supplement pool 
under Sec.  97.43 of this chapter;
    (iv) The decision on the deduction of NOX allowances 
under Sec.  97.54 of this chapter;
    (v) The decision on the transfer of NOX allowances under 
Sec.  97.61 of this chapter;
    (vi) The decision on a petition for approval of an alternative 
monitoring system;
    (vii) The approval or disapproval of a monitoring system 
certification or recertification under Sec.  97.71 of this chapter;
    (viii) The finalization of control period emissions data, including 
retroactive adjustment based on audit;
    (ix) The approval or disapproval of a petition under Sec.  97.75 of 
this chapter;

[[Page 21645]]

    (x) The determination of the sufficiency of the monitoring plan for 
a NOX Budget opt-in unit;
    (xi) The decision on a request for withdrawal of a NOX 
Budget opt-in unit from the NOX Budget Trading Program under 
Sec.  97.86 of this chapter;
    (xii) The decision on the deduction of NOX allowances 
under Sec.  97.87 of this chapter; and
    (xiii) The decision on the allocation of NOX allowances 
to a NOX Budget opt-in unit under Sec.  97.88 of this 
chapter.
* * * * *


Sec.  78.2  [Amended]

0
3. Section 78.2 is amended by removing the words ``shall apply to this 
part'' and adding in its place the words ``shall apply to appeals of 
any final decision of the Administrator under parts 72, 73, 74, 75, 76, 
or 77 of this chapter.''

0
4. Section 78.3 is amended:
0
a. In paragraph (b)(3)(i) by adding, after the word ``petitioner)'', 
the words ``or the NOX authorized account representative 
under paragraph (a)(3) of this section (unless the NOX 
authorized account representative is the petitioner)'';
0
b. In paragraph (c)(7) by adding, after the words ``title IV of the 
Act'', the words ``or part 97 of this chapter, as appropriate'';
0
c. Redesignating paragraphs (d)(2) and (d)(3) as paragraphs (d)(3) and 
(d)(4) respectively;
0
d. In newly designated paragraph (d)(3) by adding, after the words 
``Acid Rain Program'' the words ``or on an account certificate of 
representation submitted by a NOX authorized account 
representative or an application for a general account submitted by a 
NOX authorized account representative under the 
NOX Budget Trading Program''; and
0
e. Adding new paragraphs (a)(3) and (d)(2).
    The additions and revisions read as follows:


Sec.  78.3  Petition for administrative review and request for 
evidentiary hearing.

    (a) * * *
    (3) The following persons may petition for administrative review of 
a decision of the Administrator that is made under part 97 of this 
chapter and that is appealable under Sec.  78.1(a) of this part:
    (i) The NOX authorized account representative for the 
unit or any NOX Allowance Tracking System account covered by 
the decision; or
    (ii) Any interested person.
* * * * *
    (d) * * *
    (2) Any provision or requirement of part 97 of this chapter, 
including the standard requirements under Sec.  97.6 of this chapter 
and any emission monitoring or reporting requirements under part 97 of 
this chapter.
* * * * *

0
5. Section 78.4 is amended by adding two new sentences after the third 
sentence in paragraph (a) to read as follows:


Sec.  78.4  Filings.

    (a) * * * Any filings on behalf of owners and operators of a 
NOX Budget unit or source shall be signed by the 
NOX authorized account representative. Any filings on behalf 
of persons with an interest in NOX allowances in a general 
account shall be signed by the NOX authorized account 
representative. * * *
* * * * *


Sec.  78.12  [Amended]

0
6. Section 78.12 is amended in paragraph (a)(2) by adding, after the 
words ``Acid Rain permit'' the words ``NOX Budget permit, or 
other federally enforceable permit.''

PART 97--FEDERAL NOX BUDGET TRADING PROGRAM

0
1. The authority citation for part 97 continues to read as follows:

    Authority: 42 U.S.C. 7401, 7403, 7426, and 7601.


0
2. Section 97.2 is amended by:
0
a. Revising the definition of ``Continuous emission monitoring system 
or CEMS'';
0
b. In the definition of ``Fossil fuel fired'' by revising the first 
occurrence of the word ``combination'' in paragraphs (1), (2), and 
(3)(i) to read ``combustion'';
0
c. In the definition of ``Most stringent State or Federal 
NOX emissions limitation'' by removing the words ``, with 
regard to a NOX Budget opt-in unit,'';
0
d. In the third sentence of the definition of ``NOX 
allowance'' by adding the reference ``Sec.  97.40,'' after the word 
``except'';
0
e. In the definition of ``NOX Budget unit'' by removing the 
words ``Trading Program'';
0
f. In the definition of ``owner'' by adding the word ``the'' before the 
final occurrence of the word ``NOX'' in paragraph (4) of the 
definition; and
0
g. In the definition of ``Percent monitor data availability'' by 
revising the words ``Sec.  94.84(b)'' to read ``Sec.  97.84(b)'', 
revising the words ``3,672 hours per'' to read ``the total number of 
unit operating hours in the'', and by revising the symbol ``%'' to read 
``percent''.
    The revisions and additions read as follows:


Sec.  97.2  Definitions.

* * * * *
    Continuous emission monitoring system or CEMS means the equipment 
required under subpart H of this part to sample, analyze, measure, and 
provide, by means of readings taken at least once every 15 minutes 
(using an automated data acquisition and handling system (DAHS)), a 
permanent record of nitrogen oxides (NOX) emissions, stack 
gas volumetric flow rate or stack gas moisture content (as applicable), 
in a manner consistent with part 75 of this chapter. The following are 
the principal types of continuous emission monitoring systems required 
under subpart H of this part:
    (1) A flow monitoring system, consisting of a stack flow rate 
monitor and an automated DAHS. A flow monitoring system provides a 
permanent, continuous record of stack gas volumetric flow rate, in 
units of standard cubic feet per hour (scfh);
    (2) A nitrogen oxides concentration monitoring system, consisting 
of a NOX pollutant concentration monitor and an automated 
DAHS. A NOX concentration monitoring system provides a 
permanent, continuous record of NOX emissions in units of 
parts per million (ppm);
    (3) A nitrogen oxides emission rate (or NOX-diluent) 
monitoring system, consisting of a NOX pollutant 
concentration monitor, a diluent gas (CO2 or O2) 
monitor, and an automated DAHS. A NOX concentration 
monitoring system provides a permanent, continuous record of: 
NOX concentration in units of parts per million (ppm), 
diluent gas concentration in units of percent O2 or 
CO2 (percent O2 or CO2), and 
NOX emission rate in units of pounds per million British 
thermal units (lb/mmBtu); and
    (4) A moisture monitoring system, as defined in Sec.  75.11(b)(2) 
of this chapter. A moisture monitoring system provides a permanent, 
continuous record of the stack gas moisture content, in units of 
percent H2O (percent H2O).
* * * * *


Sec.  97.4  [Amended]

0
3. Section 97.4 is amended by:
0
a. Revising paragraph (a).
0
b. Amending the first sentence of paragraph (b)(1) by adding, after the 
words ``federally enforceable permit that'', the words ``restricts the 
unit to combusting only natural gas or fuel oil (as defined in Sec.  
75.2 of this chapter)

[[Page 21646]]

during a control period''; and removing ``and that'', following ``25 
tons or less'', and adding in their place ``, and'';
0
c. In paragraph (b)(4)(i) by adding, after the words ``with the 
restriction on'', the words ``fuel use and''; and
0
d. In paragraph (b)(4)(iv) by adding, after both occurrences of the 
words ``restriction on'', the words ``fuel use or'';
0
e. In paragraph (b)(4)(vi)(A) by adding, after the words ``restriction 
on'', the words ``fuel use or'';
0
f. In paragraph (b)(4)(vi)(B) by adding, after the words ``the 
restriction on'', the words ``fuel use or''.
    The revisions and additions read as follows:


Sec.  97.4  Applicability.

    (a) The following units in a State shall be a NOX Budget 
unit, and any source that includes one or more such units shall be a 
NOX Budget source, subject to the requirements of this part:
    (1)(i) For units other than cogeneration units--
    (A) For units commencing operation before January 1, 1997, a unit 
serving during 1995 or 1996 a generator--
    (1) With a nameplate capacity greater than 25 MWe and
    (2) Producing electricity for sale under a firm contract to the 
electric grid.
    (B) For units commencing operation in 1997 or 1998, a unit serving 
during 1997 or 1998 a generator--
    (1) With a nameplate capacity greater than 25 MWe and
    (2) Producing electricity for sale under a firm contract to the 
electric grid.
    (C) For units commencing operation on or after January 1, 1999, a 
unit serving at any time a generator--
    (1) With a nameplate capacity greater than 25 MWe and
    (2) Producing electricity for sale.
    (ii) For cogeneration units--
    (A) For units commencing operation before January 1, 1997, a unit 
serving during 1995 or 1996 a generator with a nameplate capacity 
greater than 25 MWe and failing to qualify as an unaffected unit under 
Sec.  72.6(b)(4) of this chapter for 1995 or 1996 under the Acid Rain 
Program.
    (B) For units commencing operation in 1997 or 1998, a unit serving 
during 1997 or 1998 a generator with a nameplate capacity grater than 
25 MWe and failing to qualify as an unaffected unit under Sec.  
72.6(b)(4) of this chapter for 1997 or 1998 under the Acid Rain 
Program.
    (C) For units commencing operation on or after January 1, 1999, a 
unit serving at any time a generator with a nameplate capacity greater 
than 25 MWe and failing to qualify as an unaffected unit under Sec.  
72.6(b)(4) of this chapter under the Acid Rain Program for any year.
    (2)(i) For units other than cogeneration units--
    (A) For units commencing operation before January 1, 1997, a unit--
    (1) With a maximum design heat input greater than 250 mmBtu/hr and
    (2) Not serving during 1995 or 1996 a generator producing 
electricity for sale under a firm contract to the electric grid.
    (B) For units commencing operation in 1997 or 1998, a unit--
    (1) With a maximum design heat input greater than 250 mmBtu/hr and
    (2) Not serving during 1997 or 1998 a generator producing 
electricity for sale under a firm contract to the electric grid.
    (C) For units commencing on or after January 1, 1999, a unit with a 
maximum design heat input greater than 250 mmBtu/hr:
    (1) At no time serving a generator producing electricity for sale; 
or
    (2) At any time serving a generator with a nameplate capacity of 25 
MWe or less producing electricity for sale and with the potential to 
use no more than 50 percent of the potential electrical output capacity 
of the unit.
    (ii) For cogeneration units--
    (A) For units commencing operation before January 1, 1997, a unit 
with a maximum design heat input greater than 250 mmBtu/hr and 
qualifying as an unaffected unit under Sec.  72.6(b)(4) of this chapter 
under the Acid Rain Program for 1995 and 1996.
    (B) For units commencing operation in 1997 or 1998, a unit with a 
maximum design heat input greater than 250 mmBtu/hr and qualifying as 
an unaffected unit under Sec.  72.6(b)(4) under the Acid Rain Program 
for 1997 and 1998.
    (C) For units commencing on or after January 1, 1999, a unit with a 
maximum design heat input greater than 250 mmBtu/hr and qualifying as 
an unaffected unit under Sec.  72.6(b)(4) of this chapter under the 
Acid Rain Program for each year.
* * * * *

0
4. Section 97.5 is amended by:
0
a. In paragraph (c)(6)(i) by removing the word ``or''
0
b. In paragraph (c)(6)(ii) by removing the period and replacing it with 
``; or''; and
0
c. Adding a new paragraph (c)(6)(iii).
    The addition reads as follows:


Sec.  97.5  Retired unit exemption.

* * * * *
    (c) * * *
    (6) * * *
    (iii) The date on which the unit resumes operation, if the unit is 
not required to submit a NOX permit application.
* * * * *


Sec.  97.40  [Amended]

0
5. Section 97.40 is amended by removing the word ``program''.


Sec.  97.42  [Amended]

0
6. Section 97.42 is amended by:
0
a. In paragraph (d)(4) by revising the words ``a control period'' to 
read ``the control period'';
0
b. In paragraph (e)(1) by adding, before the words 0.15 lb/mmBtu'' and 
``0.17 lb/mmBtu'' in the formulas, the words ``the lesser of'' and by 
adding, after the words ``0.15 lb/mmBtu'' and 0.17 lb/mmBtu'' in the 
formulas, the words ``the unit's most stringent State or Federal 
emission limitation.''
0
c. In paragraph (e)(2) by revising the words ``paragraph (c)(1)'' to 
read ``paragraph (e)(1)''.


Sec.  97.43  [Amended]

0
7. Section 97.43 is amended by removing paragraph (c)(8).


Sec.  97.51  [Amended]

0
8. Section 97.51 is amended by revising paragraph (b)(1)(i)(D) by 
adding, after the words ``with respect to'', the word 
``NOX''.

0
9. Section 97.54 is amended in paragraph (f) introductory text by 
removing the colon after the words ``as follows'' and by adding a 
period in its place and by adding a new sentence to the end of the 
paragraph to read as follows:


Sec.  97.54  Compliance.

* * * * *
    (f) * * * For each State NOX Budget Trading Program that 
is established, and approved and administered by the Administrator 
pursuant to Sec.  51.121 of this chapter, the terms ``compliance 
account'' or ``compliance accounts'', ``overdraft account'' or 
``overdraft accounts'', ``general account'' or ``general accounts'', 
``States'', and ``trading program budgets under Sec.  97.40'' in 
paragraphs (f)(1) through (f)(3) of this section shall be read to 
include respectively: A compliance account or compliance accounts 
established under such State NOX Budget Trading Program; an 
overdraft account or overdraft accounts established under such State 
NOX Budget Trading Program; a general account or general 
accounts established under such State NOX Budget Trading 
Program; the State or portion of a State covered by such State 
NOX Budget Trading Program; and the trading program budget 
of the State

[[Page 21647]]

or portion of a State covered by such State NOX Budget 
Trading Program.
* * * * *


Sec.  97.61  [Amended]

0
10. Section 97.61 is amended in paragraph (b) by revising the words 
``in a prior year or the same year as the NOX allowance transfer 
deadline'' to read ``prior to or the same as the control period to 
which the NOX allowance transfer deadline applies'' and by 
revising the words ``the control period in the same year as the 
NOX allowance transfer deadline'' to read ``the control 
period in the fourth year after the control period to which the 
NOX allowance transfer deadline applies.''

0
11. Section 97.70 is amended by:
0
a. In paragraph (a)(1) by removing the words ``Sec. Sec.  75.72 and 
Sec. Sec.  75.76''and adding in its place the words ``Sec. Sec.  75.71 
and 75.72'';
0
b. Revising paragraph (b)(3);
0
c. Revising paragraph (b)(4);
0
d. Removing paragraphs (b)(5) and (b)(6);
0
e. Redesignating paragraphs (b)(7), (b)(8) and (b)(9) as paragraphs 
(b)(5), (b)(6), and (b)(7), respectively;
0
f. Revising newly redesignated paragraphs (b)(5) and (b)(6); and
0
g. Revising paragraph (c).
    The revisions read as follows:


Sec.  97.70  General requirements.

* * * * *
    (b) * * *
    (3) For the owner or operator of a NOX Budget unit under 
Sec.  97.4(a) that commences operation on or after January 1, 2003 and 
that reports on an annual basis under Sec.  97.74(d) by the following 
dates:
    (i) The earlier of 90 unit operating days after the date on which 
the unit commences commercial operation or 180 calendar days after the 
date on which the unit commences commercial operation; or
    (ii) May 1, 2003, if the compliance date under paragraph (b)(3)(i) 
of this section is before May 1, 2003.
    (4) For the owner or operator of a NOX Budget unit under 
Sec.  97.4(a) that commences operation on or after January 1, 2003 and 
that reports on a control period basis under Sec.  97.74(d)(2)(ii), by 
the following dates:
    (i) The earlier of 90 unit operating days or 180 calendar days 
after the date on which the unit commences commercial operation, if 
this compliance date is during a control period; or
    (ii) May 1 immediately following the compliance date under 
paragraph (b)(4)(i) of this section, if such compliance date is not 
during a control period.
    (5) For the owner or operator of a NOX Budget unit that 
has a new stack or flue or add-on NOX emission controls for 
which construction is completed after the applicable deadline under 
paragraph (b)(1), (b)(2), (b)(3), or (b)(4) of this section or under 
subpart I of this part and that reports on an annual basis under Sec.  
97.74(d), by the earlier of 90 unit operating days or 180 calendar days 
after the date on which emissions first exit to the atmosphere through 
the new stack or flue or add-on NOX emission controls.
    (6) For the owner or operator of a NOX Budget unit that 
has a new stack or flue or add-on NOX emission controls for 
which construction is completed after the applicable deadline under 
paragraph (b)(1), (b)(2), (b)(3), or (b)(4) of this section or under 
subpart I of this part and that reports on a control period basis under 
Sec.  97.74(d)(2)(ii), by the following dates:
    (i) The earlier of 90 unit operating days or 180 calendar days 
after the date on which emissions first exit to the atmosphere through 
the new stack or flue or add-on NOX emission controls, if 
this compliance date is during a control period; or
    (ii) May 1 immediately following the compliance date under 
paragraph (b)(6)(i) of this section, if such compliance date is not 
during a control period.
* * * * *
    (c) Commencement of data reporting. (1) The owner or operator of 
NOX Budget units under paragraph (b)(1) or (b)(2) of this 
section shall determine, record and report NOX mass 
emissions, heat input rate, and any other values required to determine 
NOX mass emissions (e.g., NOX emission rate and 
heat input rate, or NOX concentration and stack flow rate) 
in accordance with Sec.  75.70(g) of this chapter, beginning on the 
first hour of the applicable compliance deadline in paragraph (b)(1) or 
(b)(2) of this section.
    (2) The owner or operator of a NOX Budget unit under 
paragraph (b)(3) or (b)(4) of this section shall determine, record and 
report NOX mass emissions, heat input rate, and any other 
values required to determine NOX mass emissions (e.g., 
NOX emission rate and heat input rate, or NOX 
concentration and stack flow rate) and electric and thermal output in 
accordance with Sec.  75.70(g) of this chapter, beginning on:
    (i) The date and hour on which the unit commences operation, if the 
date and hour on which the unit commences operation is during a control 
period; or
    (ii) The first hour on May 1 of the first control period after the 
date and hour on which the unit commences operation, if the date and 
hour on which the unit commences operation is not during a control 
period.
    (3) Notwithstanding paragraphs (c)(2)(i) and (c)(2)(ii) of this 
section, the owner or operator may begin reporting NOX mass 
emission data and heat input data before the date and hour under 
paragraph (c)(2)(i) or (c)(2)(ii) of this section if the unit reports 
on an annual basis and if the required monitoring systems are certified 
before the applicable date and hour under paragraph (c)(1) or (c)(2) of 
this section.
* * * * *

0
12. Section 97.71 is amended by:
0
a. Revising paragraph (a) introductory text;
0
b. In paragraphs (b)(1), (b)(2), and (b)(3)(ii) by adding the word 
``emission'' before the words ``monitoring system'' in each occurrence 
in paragraph (b)(1), in both occurrences in the first sentence of 
paragraph (b)(2), and in the one occurrence in paragraph (b)(3)(ii); 
and by revising the word ``a'' to read ``an'' after the word 
``installs'' in the second sentence of paragraph (b)(1);
0
c. In paragraphs (b)(3)(iii) and (b)(3)(iv)(C) by removing each 
occurrence of the words ``or component thereof''; and
0
d. Revising the second sentence of paragraph (c), adding two new 
sentences to the end of paragraph (c), and removing paragraphs (c)(i) 
through (iii).
    The revisions and additions read as follows:


Sec.  97.71  Initial certification and recertification procedures.

    (a) The owner or operator of a NOX Budget unit that is 
subject to an Acid Rain emissions limitation shall comply with the 
initial certification and recertification procedures of part 75 of this 
chapter for NOX-diluent CEMS, flow monitors, NOX 
concentration CEMS, or excepted monitoring systems under appendix E of 
part 75 of this chapter for NOX, under appendix D for heat 
input, or under Sec.  75.19 for NOX and heat input, except 
that:
* * * * *
    (c) * * * The owner or operator of such a unit shall also meet the 
applicable certification and recertification procedures of paragraph 
(b) of this section, except that the excepted methodology shall be 
deemed provisionally certified for use under the NOX Budget 
Trading Program as of the date on which a complete certification 
application is received by the

[[Page 21648]]

Administrator. The methodology shall be considered to be certified 
either upon receipt of a written notice of approval from the 
Administrator or, if such notice is not provided, at the end of the 
Administrator's 120 day review period. However, a provisionally 
certified or certified low mass emissions excepted methodology shall 
not be used to report data under the NOX Budget Trading 
Program prior to the applicable commencement date specified in Sec.  
75.19(a)(1)(ii) of this chapter.
* * * * *

0
13. Section 97.72 is amended by:
0
a. In paragraph (a) by adding the word ``emission'' before the words 
``monitoring system'' and the words ``subpart H,'' before ``appendix 
D''; and
0
b. In paragraph (b) by revising the words ``a monitoring system'' in 
the first sentence to read ``an emission monitoring system'', by 
removing each occurrence of the words ``or component'' in the 
paragraph, and by adding a sentence to the end of the paragraph.
    The revisions read as follows:


Sec.  97.72  Out of control periods.

* * * * *
    (b) * * * The owner or operator shall follow the initial 
certification or recertification procedures in Sec.  97.71 for each 
disapproved system.

0
14. Section 97.74 is amended by revising paragraphs (a)(1), (d)(1), and 
(d)(2)(ii) to read as follows:


Sec.  97.74  Recordkeeping and reporting.

    (a) * * *
    (1) The NOX authorized account representative shall 
comply with all recordkeeping and reporting requirements in this 
section, with the recordkeeping and reporting requirements under Sec.  
75.73 of this chapter, and with the requirements of Sec.  97.10(e)(1).
* * * * *
    (d) * * *
    (1) If a unit is subject to an Acid Rain emission limitation or if 
the owner or operator of the NOX budget unit chooses to meet 
the annual reporting requirements of this subpart H, the NOX 
authorized account representative shall submit a quarterly report for 
each calendar quarter beginning with:
    (i) For a unit for which the owner or operator intends to apply or 
applies for the early reduction credits under Sec.  97.43, the calendar 
quarter that covers May 1, 2000 through June 30, 2000. The 
NOX mass emission data shall be recorded and reported from 
the first hour on May 1, 2000; or
    (ii) For a unit that commences operation before January 1, 2003 and 
that is not subject to paragraph (d)(1)(i) of this section, the 
calendar quarter covering May 1, 2003 through June 30, 2003. The 
NOX mass emission data shall be recorded and reported from 
the first hour on May 1, 2003; or
    (iii) For a unit that commences operation on or after January 1, 
2003:
    (A) The calendar quarter in which the unit commences operation, if 
unit operation commences during a control period. The NOX 
mass emission data shall be recorded and reported from the date and 
hour when the unit commences operation; or
    (B) The calendar quarter which includes May 1 through June 30 of 
the first control period following the date on which the unit commences 
operation, if the unit does not commence operation during a control 
period. The NOX mass emission data shall be recorded and 
reported from the first hour on May 1 of that control period; or
    (iv) A calendar quarter before the quarter specified in paragraph 
(d)(1)(i), (d)(1)(ii), or (d)(1)(iii)(B) of this section, if the owner 
or operator elects to begin reporting early under Sec.  97.70(c)(3).
    (2) * * *
    (ii) Submit quarterly reports, documenting NOX mass 
emissions from the unit, only for the period from May 1 through 
September 30 of each year and including the data described in Sec.  
75.74(c)(6) of this chapter. The NOX authorized account 
representative shall submit such quarterly reports, beginning with:
    (A) For a unit for which the owner or operator intends to apply or 
applies for the early reduction credits under Sec.  97.43, the calendar 
quarter that covers May 1, 2000 through June 30, 2000. The 
NOX mass emission data shall be recorded and reported from 
the first hour on May 1, 2000; or
    (B) For a unit that commences operation before January 1, 2003 and 
that is not subject to paragraph (d)(2)(ii)(A) of this section, the 
calendar quarter covering May 1, 2003 through June 30, 2003. The 
NOX mass emission data shall be recorded and reported from 
the first hour on May 1, 2003; or
    (C) For a unit that commences operation on or after January 1, 2003 
and during a control period, the calendar quarter in which the unit 
commences operation. The NOX mass emission data shall be 
recorded and reported from the date and hour when the unit commences 
operation; or
    (D) For a unit that commences operation on or after January 1, 2003 
and not during a control period, the calendar quarter which includes 
May 1 through June 30 of the first control period following the date on 
which the unit commences operation. The NOX mass emission 
data shall be recorded and reported from the first hour on May 1 of 
that control period.
* * * * *


Sec.  97.87  [Amended]

0
15. Section 97.87 is amended in the second sentence of paragraph 
(b)(1)(iii)(A) by adding the word ``be'' after the words ``shall not''.

0
16. Subpart J consisting of Sec.  97.90 is added to part 97 to read as 
follows:

Subpart J--Appeal Procedures


Sec.  97.90  Appeal procedures.

    The appeal procedures for the NOX Budget Trading Program 
are set forth in part 78 of this chapter.

[FR Doc. 04-7973 Filed 4-20-04; 8:45 am]
BILLING CODE 6560-50-P