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

[Federal Register: April 21, 2004 (Volume 69, Number 77)]
[Rules and Regulations]
[Page 21603-21648]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[DOCID:fr21ap04-10]
[[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
NO_X SIP Call, NO_X 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 (NO_X) budgets for States subject to the
NO_X State implementation plan (SIP) Call. This final rule
requires States that submitted SIPs to meet the Phase I NO_X
SIP Call budgets to submit Phase II SIP revisions as needed to achieve
the necessary incremental reductions of NO_X. It also
requires Georgia and Missouri to submit SIP revisions meeting the full
NO_X SIP Call budgets since they were not required to submit
Phase I SIPs. These SIPs are necessary to prohibit specified amounts of
emissions of NO_X--one of the precursors to ozone (smog)
pollution--for the purposes of reducing NO_X 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 NO_X. 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
NO_X 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 NO_X 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
NO_X Budget Trading Program. Today's final rule completes
action on the June 13, 2001 proposed rule revisions for sources subject
to the Federal NO_X 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
king.jan@epa.gov. Technical questions concerning electric generating
units (EGUs) should be directed to Kevin Culligan, Office of
Atmospheric Programs, Clean Air Markets Division, (6204M), 1200
Pennsylvania Ave., NW., Washington, DC 20460, telephone (202) 564-9172,
e-mail culligan.kevin@epa.gov; technical questions concerning
stationary internal combustion (IC) engines should be directed to Doug
Grano, Office of Air Quality Planning and Standards, C539-02, Research
Triangle Park, North Carolina 27711, telephone (919) 541-3292, e-mail
grano.doug@epa.gov; legal questions should be directed to Winifred
Okoye, Office of General Counsel, (2344A), 1200 Pennsylvania Ave., NW.,
Washington, DC 20460, telephone (202) 564-5446, e-mail
okoye.winifred@epa.gov.

SUPPLEMENTARY INFORMATION:

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
NO_X 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 NO_X 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
NO_X 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 NO_X SIP Call,
(4) Revising statewide emissions budgets in the NO_X 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 NO_X 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.regulations.gov/ 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 NO_X SIP Call?
B. What Were the Court Decisions on the NO_X 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 NO_X SIP Call?
3. What Was the DC Circuit Decision on the Stay of the SIP
Submittal Schedule for the NO_X SIP Call?
4. What Was the Court's Decision on the NO_X 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 NO_X 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
NO_X 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 NO_X
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 NO_X 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, NO_X, 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 NO_X 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 NO_X emissions which significantly
contribute to downwind air quality problems. We established statewide
NO_X 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 NO_X. States have the flexibility to
adopt the appropriate mix of controls for their State to meet the
NO_X emissions reductions requirements of the NO_X
SIP Call. A number of parties, including certain States as well as
industry and labor groups, challenged our NO_X SIP Call Rule.
Independently, we also found that sources and emitting activities
in 22 States and the District of Columbia emit NO_X 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 NO_X 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 NO_X 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
NO_X 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
NO_X 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 NO_X 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
NO_X 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 NO_X SIP Call?
The NO_X SIP Call Rule required States to submit SIP
revisions by September 30, 1999. State petitioners challenging the
NO_X 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 NO_X SIP Call?
On March 3, 2000, the DC Circuit issued its decision on the
NO_X 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 NO_X SIP Call, and not the 8-hour
basis. The requirements of the NO_X 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 NO_X 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 NO_X 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 NO_X 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 NO_X SIP Call and provided that States could submit only
those portions of the NO_X SIP Call upheld by the Court
(Phase I SIPs). The existing record in the NO_X 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 NO_X
budget for each State for which the NO_X 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
NO_X 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
NO_X SIP Call, we allowed these 19 States and the District of
Columbia to submit SIPs that cover all of the NO_X 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 NO_X 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 NO_X 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 NO_X 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 NO_X SIP Call would have 1,309 days for
implementing the SIP as provided in the original NO_X SIP Call.

C. What Was Contained in the Section 126 Rule?

We have also addressed interstate NO_X 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 NO_X emissions
limits for the affected sources and set a May 1, 2003 compliance
date.\5\ We promulgated a NO_X 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 NO_X 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 NO_X 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 NO_X 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 NO_X SIP
Call requirements, including the originally promulgated May 1, 2003
compliance deadline [40 CFR 52.34(i)]. The Court changed the
NO_X 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 NO_X 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 NO_X 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 NO_X 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 NO_X SIP Call, Section 126,
and Technical Amendments rulemakings as follows:
(1) Remanded the portion of the NO_X SIP Call
requirements based on the assumed control level for stationary IC engines;
(2) Delayed the NO_X SIP Call SIP submittal date to
October 30, 2000. Michigan;
(3) Delayed the date for implementation of the NO_X SIP
Call reductions to May 31, 2004. Michigan;
(4) Remanded and vacated the inclusion of Wisconsin. Michigan;
(5) Remanded and vacated the NO_X SIP Call budgets for
Georgia and Missouri under the 1-hour ozone NAAQS. Michigan;
(6) Remanded and vacated the NO_X 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
NO_X 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 NO_X
SIP Call SIP revision. Further, we advised Georgia and Missouri that
they did not have to submit NO_X SIP Call SIPs at this time.
We advised Alabama and Michigan that although the Court upheld the
NO_X 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 NO_X 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
NO_X 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 NO_X 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 NO_X 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 NO_X SIP Call or
Section 126 Rule issues related to the 8-hour ozone NAAQS. Although we
stayed the findings on the NO_X 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 NO_X 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 NO_X 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 NO_X 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 NO_X 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 NO_X SIP Call.
(4) Changes to the statewide NO_X budgets in the
NO_X 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 NO_X 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 NO_X 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 NO_X 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 NO_X 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 NO_X 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 NO_X 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 NO_X 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
NO_X 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 NO_X 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 NO_X 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 NO_X 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
NO_X 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 NO_X/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 [NO_X 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 NO_X 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
NO_X 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 NO_X.
In response to the February 22, 2002 proposed rule, most commenters
again argued that, under the NO_X 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 NO_X 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 NO_X.
However, at this time, we do not believe we have adequate record
information comparing the NO_X 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
NO_X 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 NO_X SIP Call Definition of EGU?
In the NO_X 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 NO_X SIP Call used the following methodology for
classifying all units (including cogeneration units) in the States
subject to the NO_X 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 NO_X 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 NO_X 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 NO_X 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
NO_X 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 NO_X 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 NO_X SIP Call and Section 126 rulemakings
have advocated--we believe that it is prudent to gain experience in
operating the trading program under the NO_X 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
NO_X allowances. After we have gained experience with the
NO_X 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 NO_X 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 NO_X 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 NO_X. However, at
this time, we do not believe we have adequate record support comparing
the NO_X 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 NO_X 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 NO_X.
---------------------------------------------------------------------------

\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
NO_X 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 NO_X 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
NO_X 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 NO_X 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 NO_X emissions can be
achieved in the same manner. Any post-combustion pollution control
device used for NO_X 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 NO_X 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
NO_X 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 NO_X to elemental nitrogen and
water. Because the NO_X 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
NO_X to elemental nitrogen and water. Because the
NO_X 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 NO_X 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
NO_X control identified by boiler and NO_X 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: NO_X 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 NO_X
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 NO_X 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
NO_X 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 NO_X 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 NO_X 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 NO_X 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 NO_X removed.
This is higher than the average cost for EGUs because the unit
started at a low NO_X 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
NO_X rate, the cost would be the same.
---------------------------------------------------------------------------

4. What Revisions Are Being Made to the Definition of EGU in the
NO_X 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 NO_X 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 NO_X 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 NO_X 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 NO_X 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 NO_X 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 NO_X 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 NO_X 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
NO_X 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 NO_X 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 NO_X 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 NO_X 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 NO_X 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 NO_X 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 NO_X 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 NO_X 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
NO_X 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 NO_X 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
NO_X 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 NO_X 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 NO_X SIP Call final rule, after
determining the degree to which NO_X emissions, as a whole
from the particular upwind States, contribute to downwind nonattainment
or maintenance problems, we determined whether any amounts of the
NO_X 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 NO_X controls, we
determined that an average of approximately $2,000 per ton removed is
highly cost effective. We first projected the total amount of
NO_X 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 NO_X
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
NO_X 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 NO_X Control
(1) NO_X 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''
NO_X 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 NO_X 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 NO_X 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
NO_X 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 NO_X 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
NO_X SIP Call population, that the NO_X 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 NO_X 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 NO_X 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 NO_X 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 NO_X 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 NO_X 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 NO_X 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 NO_X SIP Call
area. Forty-two data points were collected (see RTC or TSD for
details). The average uncontrolled NO_X 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 NO_X 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 NO_X 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 NO_X 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
NO_X 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) NO_X 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 NO_X SIP Call
States that are retrofit with LEC technology and for which they could
obtain State NO_X permit limits. The average post-control
NO_X permit levels for 2-stroke and 4-stroke engines are
reported to be 5.0 and 3.7, respectively. The INGAA states that
NO_X permit limits are appropriate for use in calculating the
average post-control emission rate for lean-burn engines in the
NO_X SIP Call area for the following reasons:
? These engines are located in the NO_X
SIP Call States, and represent the same makes and models as the large
NO_X 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 NO_X 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 NO_X 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 NO_X 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
NO_X 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
NO_X 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 NO_X 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 NO_X 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 NO_X 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
NO_X SIP Call area. In addition, INGAA identified engines
that had been retrofit with LEC in the NO_X 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
NO_X SIP Call area. Data from the EPA Regional Offices and
other emission test results were obtained. The results for large
engines in the NO_X SIP Call area show that 43 of the 58
tests have NO_X 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 NO_X 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 NO_X 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 NO_X SIP Call area shows that 60 of
the 79 tests have NO_X 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 NO_X
SIP Call area, we agree with commenters that it is reasonable to focus
on the set of data for large engines in the NO_X SIP Call area.
The set of data for large engines in the NO_X SIP Call
area cover 80 percent of the engine models in the NO_X 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 NO_X 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 NO_X 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
NO_X 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 NO_X 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 NO_X 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 NO_X 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 NO_X 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 NO_X
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 NO_X 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 NO_X 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 NO_X SIP Call budget.
b. Flexibility/Averaging
Comment: Several commenters noted that the response of IC engines
to retrofit NO_X controls is highly variable and that the
average NO_X reduction used to calculate the NO_X
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 NO_X 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 NO_X
SIP Call inventory develop company-specific compliance plans to
demonstrate achievement of NO_X 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 NO_X
reductions in the NO_X SIP Call Rule:
? Engine owners and operators would accept
enforceable and verifiable measures to control engines to meet assigned
NO_X 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 NO_X 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 NO_X 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 NO_X 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 NO_X 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 NO_X
SIP Call budget, it is an important issue as States take steps to meet
their NO_X 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 NO_X SIP Call (Docket No. OAR-2001-0008,
Item No. XII-C-115).
---------------------------------------------------------------------------

During the SIP development process, the States may establish an
NO_X 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 NO_X SIP Call. These control measures
would be adopted as part of the SIP and must yield enforceable and
demonstrable reductions equal to the NO_X 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 NO_X 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
NO_X controls for compliance with the NO_X 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 NO_X
SIP Call requirements will not trigger NSR for NO_X 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 NO_X 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 NO_X
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 NO_X 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 NO_X 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 NO_X SIP Call budget demonstration.
e. Presumptive Technology
Comment: Because of the variability of gas pipeline engines in the
NO_X SIP Call area, industry commenters suggest that State
air agencies should assign NO_X 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
NO_X reduction effectiveness. The definition and presumption
are not necessary to establish the NO_X 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 NO_X 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
NO_X 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 NO_X 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 NO_X 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 NO_X 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
NO_X 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 NO_X 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 NO_X SIP Call Rule, to prohibit those amounts of
NO_X emissions which significantly contribute to downwind
nonattainment. See, NO_X 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\ NO_X emissions for
Georgia indicates that the amount of NO_X 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
NO_X 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 NO_X 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 NO_X 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 NO_X 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 NO_X 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 NO_X 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 NO_X 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 NO_X 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 NO_X 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 NO_X 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
NO_X 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 NO_X 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 NO_X
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
NO_X 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 NO_X 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 NO_X 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
NO_X SIP Call, a State may, of course, assess the in-State
impacts of NO_X emissions from its coarse grid area, and
impose additional NO_X reductions, beyond the NO_X
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 NO_X 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 NO_X
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 NO_X 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 NO_X 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 NO_X 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 NO_X 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 NO_X 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 NO_X 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 NO_X 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
NO_X 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 NO_X 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 NO_X 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 NO_X 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 NO_X 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 NO_X 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 NO_X limits the commenter cites
have since been revised by the State and are yet to be approved by EPA.
Further, completing the NO_X SIP Call in Missouri is an
equitable approach. It would be inequitable to use 2003 air quality
analysis for Missouri but to hold other NO_X SIP Call States
to the 1998 analysis. It should also be noted that we intend to review
the NO_X 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 NO_X
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 NO_X
emissions and greater improvements than the NO_X SIP Call.
Response: We disagree. Missouri adopted and, in December 2000, we
approved a statewide NO_X 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
NO_X to other areas that we had identified in the
NO_X SIP Call. Revisions to the statewide NO_X rule
were adopted on April 24, 2003 and were submitted as a SIP revision on
September 18, 2003.
Both the SIP-approved statewide NO_X rule and the
revisions to the rule submitted to EPA would achieve less
NO_X emissions reductions than implementation of the
NO_X SIP Call. Missouri's current and proposed revised
NO_X rules are less stringent than the NO_X SIP
Call requirements. The emissions reductions under the NO_X
SIP Call are greater by about 20 percent statewide and 40 percent in
the fine grid compared to the SIP-approved Missouri rule. The
NO_X 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 NO_X 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 NO_X 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 NO_X reductions throughout the entire State.
Thus, the emissions reductions are not focused in the geographical area
of interest.
The NO_X SIP Call budget also includes reductions in
emissions from large cement kilns, industrial boilers, and stationary
IC engines. The NO_X 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 NO_X 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
NO_X 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 NO_X
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 NO_X 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 NO_X 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 NO_X 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 NO_X
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 NO_X 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 NO_X 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 NO_X 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 NO_X 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
NO_X 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 NO_X SIP Call emission
inventory in a Technical Amendment published May 14, 1999, in response
to comments on the 2007 baseline sub-inventory in the NO_X
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
NO_X SIP Call for submitted data which was determined to be
technically justified.
In some cases, States have made minor corrections to their
NO_X SIP Call emission inventory as part of their response to
the NO_X 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 NO_X SIP Call submittal. Today's rulemaking on
the Phase II NO_X SIP Call requirements is based on the
corrections to the NO_X 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 NO_X SIP Call, ``[t]he control measures that
the State chooses to require will become the enforceable mechanism
under the NO_X 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
NO_X 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 NO_X
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 NO_X SIP Call proposal
regarding electric reliability during the initial years of the program.
In the NO_X 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 NO_X SIP Call.
Consequently, to be consistent with the original 2-year window
specified in the NO_X 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 NO_X 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 NO_X 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 NO_X 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
NO_X 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 NO_X allocations generated by IC engines.
The commenter also claims that because IC engines will also have to be
retrofitted to comply with the NO_X SIP Call they could also
have reliability problems and, therefore, should be able to receive
allowances from the CSP.
Under the NO_X SIP Call, the CSP is limited to use by the
large boilers and turbines that are in the NO_X Budget
Trading Program. Because IC engines are not in the NO_X
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 NO_X SIP Call and Phase III of the OTC
NO_X Budget program. It also reallocated the three States' CSPs.
Under the three-State MOU, Connecticut, Massachusetts, and Rhode
Island would collectively be meeting their NO_X 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' NO_X SIP Call SIP submittals, with budgets that
reflected the three-State MOU, as collectively meeting their
NO_X 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
NO_X 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
NO_X SIP Call, transportation conformity budgets must reflect
the mobile source controls assumed in the NO_X 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 NO_X SIP Call, we offered to administer a
multi-State NO_X Budget Trading Program for States affected by

[[Page 21631]]

the NO_X 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 NO_X
SIP Call region that, for these four States, includes only the portion
of the States we are including in the NO_X SIP Call. In the
final NO_X 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 NO_X SIP Call or the
Section 126 rulemaking to trade with each other through the mechanisms
of the NO_X Budget Trading Program provided certain criteria
were met. These criteria included that States must be subject to the
NO_X SIP Call and that States must meet the emission control
level under the final rule for the NO_X SIP Call. The
justification for allowing trading across States is the test of
significant contribution which underlies both the Section 126
rulemaking and the NO_X 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 NO_X SIP Call or the
Section 126 rulemaking.
1. How Will Flow Control Be Handled for Georgia and Missouri?
The NO_X 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 NO_X 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 NO_X 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
NO_X SIP Call and applies to the entire NO_X 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 NO_X SIP Call provided that flow control provisions
apply starting in the second year of the NO_X 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 NO_X SIP Call established May 1, 2003 as
the commencement date for the NO_X 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 NO_X SIP Call rulemaking, the D.C.
Circuit delayed the commencement date for the NO_X 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 NO_X 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 NO_X 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 NO_X 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 NO_X 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 NO_X 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 NO_X 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 NO_X 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
NO_X 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 NO_X 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 NO_X 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 NO_X 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
NO_X strategy and by Georgia and Missouri's NO_X
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 NO_X 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 NO_X SIP Call into two phases--
Phase I which accounted for 90 percent of the total reductions required
by the NO_X SIP Call, and Phase II which will achieve
approximately 10 percent of the total reductions required by the
NO_X SIP Call. Thus, because Phase II of the NO_X
SIP Call requires relatively smaller NO_X 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 NO_X SIP Call, with September 30, 1999 as
the submission date. On May 25, 1999, in response to a request by
States challenging the NO_X 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
NO_X SIP Call.
In setting this timeframe, we also recognize that the proposed
NO_X 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
NO_X 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 NO_X 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 NO_X 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
NO_X 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 NO_X 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 NO_X
allowances to cover their ozone season NO_X 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 NO_X

[[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 NO_X 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 NO_X 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
NO_X SIP Call reflect the emissions reductions mandated under
the NO_X 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 NO_X 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 NO_X SIP Call, which had a compliance deadline
of May 1, 2003. The original NO_X 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 NO_X 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 NO_X SIP Call requirements that applies to sources
for the Phase I compliance pursuant to the original NO_X 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 NO_X SIP Call, some States
may seek emissions reductions from source categories other than IC
engines. Other States have already met their NO_X budgets and
do not need to further control IC engines for purposes of the
NO_X SIP Call. Still other States have met at least a portion
of the Phase II NO_X 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 NO_X SIP Call States. These emissions reductions
help States meet their NO_X 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 NO_X SIP Call area have LEC.\52\ Many engines
in the NO_X SIP Call area already have decreased
NO_X 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 NO_X 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 NO_X 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 NO_X 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 ``NO_X 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
NO_X requirements following State/local rule adoption. These
timeframes generally illustrate the successful implementation of past
regulatory programs involving the installation of NO_X controls.
In the 1990 Amendments to the CAA, Congress added RACT requirements
for major sources of NO_X. All categories of major
NO_X 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 NO_X RACT SIP revisions,
we approved NO_X 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
NO_X 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
NO_X 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 NO_X 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 NO_X SIP Call since 1998. In
addition, as discussed earlier, States are free to choose which sources
to regulate in compliance with the NO_X SIP Call
requirements. Also, some States have already adopted SIPs that meet the
full NO_X 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
NO_X 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 NO_X 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 NO_X 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
NO_X SIP Call. Projects in Georgia and Missouri, being
constructed after the bulk of the SCRs for the NO_X 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 NO_X 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 NO_X
SIP Call. 42 U.S.C. 7410(a)(2)(D)(i)(I). The Court held that ``EPA
erroneously included Wisconsin in the NO_X 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
NO_X 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
NO_X 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 NO_X SIP Call to conform to the Court's decision. In
addition, we received only one comment on excluding Wisconsin from the
NO_X 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 NO_X
SIP Call. Although we stayed the 8-hour basis of the NO_X 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 NO_X SIP Call does not address
whether Wisconsin should remain subject to the 8-hour basis of the
NO_X 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 NO_X 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
NO_X 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 NO_X 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 NO_X 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 NO_X 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 NO_X SIP Call, but using
an updated model and updated inputs that reflect current requirements,
including the NO_X 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 NO_X
SIP Call. For a more detailed discussion of how the NO_X 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 NO_X 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 NO_X SIP
Call, (Michigan v. EPA, 213 F. 3d 663 (DC Cir. 2000), cert denied, 121
S. Ct. 1225 (2001)), the NO_X 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 NO_X SIP Call into two phases (Phase I and Phase II),
thereby enabling the Agency to proceed with those portions of the
NO_X 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
NO_X 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 NO_X 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 NO_X 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 NO_X 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
NO_X 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 NO_X 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
NO_X SIP Call. Section 51.121(c)(2) also defines the fine
grid for purposes of the NO_X SIP Call.
Section 51.121(d) is modified to reflect dates by which all the
States subject to the NO_X 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 NO_X budgets for each State. Section 51.121(e)(2)(i)
contains the modified table reflecting changes to the State-by-State
NO_X 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 NO_X
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
NO_X 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 NO_X SIP Call
requirements is modified. This revision is consistent with the original
2-year window specified in the NO_X 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 NO_X 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 NO_X
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
NO_X Budget Trading Program under the NO_X SIP
Call. In particular, the final revisions refer to ``the control period
to which the NO_X allowance transfer deadline applies,''
rather than referencing ``the control period in the same year as the
NO_X 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 NO_X emission controls.'' As a
result, Sec. 97.70(b)(5) and (6) contain the same references to new
stacks, flues, or add-on NO_X 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) (NO_X 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) (NO_X
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 NO_X 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
NO_X SIP Call RIA entitled, ``NO_X Emissions
Control Costs for Stationary Reciprocating Internal Combustion Engines
in the NO_X SIP Call States'' (August 11, 2000) and
``Stationary Reciprocating Internal Combustion Engines: Updated
Information on NO_X 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 NO_X 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 NO_X 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 NO_X SIP Call, Section 126 Rule, and NO_X SIP
Call Technical Amendments, respectively). The RIA for the original
final NO_X 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
NO_X 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 NO_X 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 NO_X 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 NO_X 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 NO_X 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 NO_X 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 NO_X 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)
(NO_X 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 NO_X SIP Call Technical Amendments.
Appalachian Power v. EPA, 251 F.3d 1026 (DC Cir. 2001) (NO_X
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 NO_X SIP
Call. Thus, today's action does not alter the relationship established
by the final NO_X 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 NO_X SIP Call Rule to
choose the control requirements necessary to address the transported
emissions identified by EPA in the NO_X SIP Call Rule.
As provided in the final action promulgating the NO_X SIP
Call Rule and the Technical Amendments, the NO_X 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'' (59 FR 22951, 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
NO_X 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 NO_X
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 NO_X 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
NO_X SIP Call region, as well as all NO_X 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 NO_X reduction at relatively low cost, with an
average cost of less than $2,000 (1990 dollars) per ozone season ton of
NO_X 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
NO_X 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 NO_X 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
NO_X 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 NO_X 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 NO_X 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\ ``NO_X 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 NO_X budgets, we do not believe the
concerns expressed about effects on natural gas transmission from
compliance with the Phase II NO_X 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 NO_X SIP Call, and NO_X 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 NO_X SIP Call (63 FR 57477,
October 27, 1998), the NO_X 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
NO_X 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.

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

PART 51--[Amended]

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

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

? 2. Section 51.121 is amended:
? a. By adding paragraph (a)(3).
? 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.
? c. By revising paragraph (c).
? d. By revising paragraph (d)(1).
? e. By revising paragraphs (e)(1) and (e)(2).
? f. By redesignating paragraphs (e)(3) and (e)(4) as (e)(4) and (e)(5).
? g. By adding a new paragraph (e)(3).
? 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
NO_X 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 NO_X 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 NO_X budget for a State listed in paragraph (c) of this
section is defined as the total amount of NO_X 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 NO_X 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 NO_X budget is defined as the total
amount of NO_X 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 NO_X
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 NO_X
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.
* * * * *

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

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

* * * * *
(g) * * *
(1) Data collection is to begin during the ozone season 1 year
prior to the State's NO_X 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 info.chief@epa.gov. 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

? 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.

? 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 NO_X
allowances based on the information, as adjusted, under Sec. 97.31 of
this chapter;
(ii) The decision on the allocation of NO_X allowances to
a NO_X Budget unit under Sec. 97.41(b), (c), (d), or (e) of
this chapter;
(iii) The decision on the allocation of NO_X allowances
to a NO_X Budget unit from the compliance supplement pool
under Sec. 97.43 of this chapter;
(iv) The decision on the deduction of NO_X allowances
under Sec. 97.54 of this chapter;
(v) The decision on the transfer of NO_X 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 NO_X Budget opt-in unit;
(xi) The decision on a request for withdrawal of a NO_X
Budget opt-in unit from the NO_X Budget Trading Program under
Sec. 97.86 of this chapter;
(xii) The decision on the deduction of NO_X allowances
under Sec. 97.87 of this chapter; and
(xiii) The decision on the allocation of NO_X allowances
to a NO_X Budget opt-in unit under Sec. 97.88 of this chapter.
* * * * *

Sec. 78.2 [Amended]

? 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.''

? 4. Section 78.3 is amended:
? a. In paragraph (b)(3)(i) by adding, after the word ``petitioner)'',
the words ``or the NO_X authorized account representative
under paragraph (a)(3) of this section (unless the NO_X
authorized account representative is the petitioner)'';
? 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'';
? c. Redesignating paragraphs (d)(2) and (d)(3) as paragraphs (d)(3) and
(d)(4) respectively;
? 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 NO_X authorized account
representative or an application for a general account submitted by a
NO_X authorized account representative under the
NO_X Budget Trading Program''; and
? 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 NO_X authorized account representative for the
unit or any NO_X 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.
* * * * *

? 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
NO_X Budget unit or source shall be signed by the
NO_X authorized account representative. Any filings on behalf
of persons with an interest in NO_X allowances in a general
account shall be signed by the NO_X authorized account
representative. * * *
* * * * *

Sec. 78.12 [Amended]

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

PART 97--FEDERAL NOX BUDGET TRADING PROGRAM

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

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

? 2. Section 97.2 is amended by:
? a. Revising the definition of ``Continuous emission monitoring system
or CEMS'';
? 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'';
? c. In the definition of ``Most stringent State or Federal
NO_X emissions limitation'' by removing the words ``, with
regard to a NO_X Budget opt-in unit,'';
? d. In the third sentence of the definition of ``NO_X
allowance'' by adding the reference ``Sec. 97.40,'' after the word
``except'';
? e. In the definition of ``NO_X Budget unit'' by removing the
words ``Trading Program'';
? f. In the definition of ``owner'' by adding the word ``the'' before the
final occurrence of the word ``NO_X'' in paragraph (4) of the
definition; and
? 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 (NO_X) 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 NO_X pollutant concentration monitor and an automated
DAHS. A NO_X concentration monitoring system provides a
permanent, continuous record of NO_X emissions in units of
parts per million (ppm);
(3) A nitrogen oxides emission rate (or NO_X-diluent)
monitoring system, consisting of a NO_X pollutant
concentration monitor, a diluent gas (CO₂ or O₂)
monitor, and an automated DAHS. A NO_X concentration
monitoring system provides a permanent, continuous record of:
NO_X concentration in units of parts per million (ppm),
diluent gas concentration in units of percent O₂ or
CO₂ (percent O₂ or CO₂), and
NO_X 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]

? 3. Section 97.4 is amended by:
? a. Revising paragraph (a).
? 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'';
? c. In paragraph (b)(4)(i) by adding, after the words ``with the
restriction on'', the words ``fuel use and''; and
? d. In paragraph (b)(4)(iv) by adding, after both occurrences of the
words ``restriction on'', the words ``fuel use or'';
? e. In paragraph (b)(4)(vi)(A) by adding, after the words ``restriction
on'', the words ``fuel use or'';
? 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 NO_X Budget
unit, and any source that includes one or more such units shall be a
NO_X 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.
* * * * *

? 4. Section 97.5 is amended by:
? a. In paragraph (c)(6)(i) by removing the word ``or''
? b. In paragraph (c)(6)(ii) by removing the period and replacing it with
``; or''; and
? 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 NO_X permit application.
* * * * *

Sec. 97.40 [Amended]

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

Sec. 97.42 [Amended]

? 6. Section 97.42 is amended by:
? a. In paragraph (d)(4) by revising the words ``a control period'' to
read ``the control period'';
? 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.''
? c. In paragraph (e)(2) by revising the words ``paragraph (c)(1)'' to
read ``paragraph (e)(1)''.

Sec. 97.43 [Amended]

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

Sec. 97.51 [Amended]

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

? 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 NO_X 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 NO_X Budget Trading Program; an
overdraft account or overdraft accounts established under such State
NO_X Budget Trading Program; a general account or general
accounts established under such State NO_X Budget Trading
Program; the State or portion of a State covered by such State
NO_X Budget Trading Program; and the trading program budget
of the State

[[Page 21647]]

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

Sec. 97.61 [Amended]

? 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 NO_X allowance transfer deadline applies'' and by
revising the words ``the control period in the same year as the
NO_X allowance transfer deadline'' to read ``the control
period in the fourth year after the control period to which the
NO_X allowance transfer deadline applies.''

? 11. Section 97.70 is amended by:
? 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'';
? b. Revising paragraph (b)(3);
? c. Revising paragraph (b)(4);
? d. Removing paragraphs (b)(5) and (b)(6);
? e. Redesignating paragraphs (b)(7), (b)(8) and (b)(9) as paragraphs
(b)(5), (b)(6), and (b)(7), respectively;
? f. Revising newly redesignated paragraphs (b)(5) and (b)(6); and
? g. Revising paragraph (c).
The revisions read as follows:

Sec. 97.70 General requirements.

* * * * *
(b) * * *
(3) For the owner or operator of a NO_X 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 NO_X 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 NO_X Budget unit that
has a new stack or flue or add-on NO_X 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 NO_X emission controls.
(6) For the owner or operator of a NO_X Budget unit that
has a new stack or flue or add-on NO_X 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 NO_X 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
NO_X Budget units under paragraph (b)(1) or (b)(2) of this
section shall determine, record and report NO_X mass
emissions, heat input rate, and any other values required to determine
NO_X mass emissions (e.g., NO_X emission rate and
heat input rate, or NO_X 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 NO_X Budget unit under
paragraph (b)(3) or (b)(4) of this section shall determine, record and
report NO_X mass emissions, heat input rate, and any other
values required to determine NO_X mass emissions (e.g.,
NO_X emission rate and heat input rate, or NO_X
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 NO_X 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.
* * * * *

? 12. Section 97.71 is amended by:
? a. Revising paragraph (a) introductory text;
? 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);
? c. In paragraphs (b)(3)(iii) and (b)(3)(iv)(C) by removing each
occurrence of the words ``or component thereof''; and
? 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 NO_X 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 NO_X-diluent CEMS, flow monitors, NO_X
concentration CEMS, or excepted monitoring systems under appendix E of
part 75 of this chapter for NO_X, under appendix D for heat
input, or under Sec. 75.19 for NO_X 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 NO_X 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 NO_X Budget Trading
Program prior to the applicable commencement date specified in Sec.
75.19(a)(1)(ii) of this chapter.
* * * * *

? 13. Section 97.72 is amended by:
? a. In paragraph (a) by adding the word ``emission'' before the words
``monitoring system'' and the words ``subpart H,'' before ``appendix
D''; and
? 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.

? 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 NO_X 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 NO_X budget unit chooses to meet
the annual reporting requirements of this subpart H, the NO_X
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
NO_X 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
NO_X 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 NO_X
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 NO_X 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 NO_X 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 NO_X 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
NO_X 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
NO_X 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 NO_X 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 NO_X mass emission
data shall be recorded and reported from the first hour on May 1 of
that control period.
* * * * *

Sec. 97.87 [Amended]

? 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''.

? 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 NO_X 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

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