# Supplemental Proposal for the Rule To Reduce Interstate Transport of Fine Particulate Matter and Ozone (Clean Air Interstate Rule)

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URL: https://www.frixlaw.com/law-library/documents/fr%3A04-11923

## Record

- **Collection:** Federal Register
- **Document type:** Proposed Rule
- **Published:** June 10, 2004
- **Citation:** 69 FR 32684

## Text

ENVIRONMENTAL PROTECTION AGENCY
40 CFR Parts 51, 72, 73, 74, 77, 78 and 96
[OAR-2003-0053; FRL-7667-1]
RIN 2060-AL76
Supplemental Proposal for the Rule To Reduce Interstate Transport of Fine Particulate Matter and Ozone (Clean Air Interstate Rule)

AGENCY:

Environmental Protection Agency (EPA).

ACTION:

Supplemental notice of proposed rulemaking.

SUMMARY:

Today's action is a supplemental notice of proposed rulemaking (SNPR) to EPA's January 30, 2004 (69 FR 4566) notice of proposed rulemaking (NPR). The NPR requires certain States to submit State implementation plan (SIP) measures to ensure that emissions reductions are achieved as needed to mitigate transport of fine particulate matter (PM2.5) and/or ozone pollution and its main precursors—emissions of sulfur dioxide (SO
2
) and oxides of nitrogen (NO
X
)—across State boundaries. Today's action includes proposed rule language and supplemental information for the January 2004 proposal, consisting of further discussion on establishing State-level emissions budgets, proposed State reporting requirements and SIP approvability criteria, proposed model cap-and-trade rules, and a more thorough discussion of how this proposal interacts with existing Clean Air Act (CAA) programs and requirements.

The EPA intends to produce a final rule by the end of calendar year 2004.

DATES:

Comments must be received on or before July 26, 2004. A public hearing will be held on June 3, 2004 in Alexandria, Virginia. Please refer to
SUPPLEMENTARY INFORMATION
for additional information on the comment period and the public hearing.

ADDRESSES:

Submit your comments, identified by Docket ID No. OAR-2003-0053, by one of the following methods:

• Federal eRulemaking Portal:
http://www.regulations.gov
. Follow the on-line instructions for submitting comments.

• Agency Web site:
http://www.epa.gov/edocket
. EDOCKET, EPA's electronic public docket and comment system, is EPA's preferred method for receiving comments. Follow the on-line instructions for submitting comments.

• E-mail:
A-and-R-Docket@epa.gov
.

• Mail: Air Docket, Clean Air Interstate Rule.

• Environmental Protection Agency, Mailcode: 6102T, 1200 Pennsylvania Ave., NW., Washington, DC 20460.

• Hand Delivery: EPA Docket Center, 1301 Constitution Avenue, NW., Room B108, Washington, DC. Such deliveries are only accepted during the Docket's normal hours of operation, and special arrangements should be made for deliveries of boxed information.

Instructions: Direct your comments to Docket ID No. OAR-2003-0053. The EPA's policy is that all comments received will be included in the public docket without change and may be made available online at
http://www.epa.gov/edocket
, including any personal information provided, unless the comment includes information claimed to be Confidential Business Information (CBI) or other information whose disclosure is restricted by statute. Do not submit information that you consider to be CBI or otherwise protected through EDOCKET, regulations.gov, or e-mail. The EPA EDOCKET and the Federal regulations.gov websites are “anonymous access” systems, which means EPA will not know your identity or contact information unless you provide it in the body of your comment. If you send an e-mail comment directly to EPA without going through EDOCKET or regulations.gov, your e-mail address will be automatically captured and included as part of the comment that is placed in the public docket and made available on the Internet. If you submit an electronic comment, EPA recommends that you include your name and other contact information in the body of your comment and with any disk or CD-ROM you submit. If EPA cannot read your comment due to technical difficulties and cannot contact you for clarification, EPA may not be able to consider your comment. Electronic files should avoid the use of special characters, any form of encryption, and be free of any defects or viruses. For additional information about EPA's public docket visit EDOCKET on-line or see the
Federal Register
of May 31, 2002 (67 FR 38102). For additional instructions on submitting comments, go to Unit I of the
SUPPLEMENTARY INFORMATION
section of this document.

Docket: All documents in the docket are listed in the EDOCKET index at
http://www.epa.gov/edocket
. Although listed in the index, some information is not publicly available,
i.e.
, CBI or other information whose disclosure is restricted by statute. Certain other material, such as copyrighted material, is not placed on the Internet and will be publicly available only in hard copy form. Publicly available docket materials are available either electronically in EDOCKET or in hard copy at the EPA Docket Center, EPA West, Room B102, 1301 Constitution Avenue, NW., Washington, DC. The 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 number for the Air Docket is (202) 566-1742.

FOR FURTHER INFORMATION CONTACT:

For general questions concerning today's action, please contact Scott Mathias, U.S. EPA, Office of Air Quality Planning and Standards, Air Quality Strategies and Standards Division, C539-01, Research Triangle Park, NC, 27711, telephone (919) 541-5310, e-mail at
mathias.scott@epa.gov
. For legal questions, please contact Howard J. Hoffman, U.S. EPA, Office of General Counsel, Mail Code 2344A, 1200 Pennsylvania Avenue, NW., Washington, DC, 20460, telephone (202) 564-5582, e-mail at
hoffman.howard@epa.gov
. For questions regarding air quality analyses, please contact Brian Timin, U.S. EPA, Office of Air Quality Planning and Standards, Emissions Modeling and Analysis Division, D243-01, Research Triangle Park, NC, 27711, telephone (919) 541-1850, e-mail at
timin.brian@epa.gov
. For questions regarding emissions reporting requirements, please contact Bill Kuykendal, U.S. EPA, Office of Air Quality Planning and Standards, Emissions Modeling and Analysis Division, Mail Code D205-01, Research Triangle Park, NC, 27711, telephone (919) 541-5372, e-mail at
kuykendal.bill@epa.gov
. For questions regarding the model cap-and-trade programs, please contact Sam Waltzer, U.S. EPA, Office of Atmospheric Programs, Clean Air Markets Division, Mail Code 6204J, 1200 Pennsylvania Avenue, NW., Washington, DC, 20460, telephone (202) 343-9175, e-mail at
waltzer.sam@epa.gov
. For questions regarding analyses required by statutes and executive orders, please contact Linda Chappell, U.S. EPA, Office of Air Quality Planning and Standards, Air Quality Strategies and Standards Division, Mail Code C339-01, Research Triangle Park, NC, 27711, telephone (919) 541-2864, e-mail at
chappell.linda@epa.gov
.

SUPPLEMENTARY INFORMATION:

I. Additional Information on Submitting Comments

A. How Can I Help EPA Ensure That My Comments Are Reviewed Quickly?

To expedite review of your comments by Agency staff, you are encouraged to send a separate copy of your comments, in addition to the copy you submit to the official docket, to Douglas Solomon, U.S. EPA, Office of Air Quality Planning and Standards, Emissions Modeling and Analysis Division, Mail Code C304-01, Research Triangle Park, NC, 27711, telephone (919) 541-4132, e-mail
iaqrcomments@epa.gov.

B. What Should I Consider as I Prepare My Comments for EPA?

1. Submitting CBI. Do not submit this information to EPA through EDOCKET, regulations.gov or e-mail. Clearly mark the part or all of the information that you claim to be CBI. For CBI information in a disk or CD ROM that you mail to EPA, mark the outside of the disk or CD ROM as CBI and then identify electronically within the disk or CD ROM the specific information that is claimed as CBI. In addition to one complete version of the comment that includes information claimed as CBI, a copy of the comment that does not contain the information claimed as CBI must be submitted for inclusion in the public docket. Information so marked will not be disclosed except in accordance with procedures set forth in 40 CFR part 2. Send or deliver information identified as CBI only to the following address: Roberto Morales, U.S. EPA, Office of Air Quality Planning and Standards, Mail Code C404-02, Research Triangle Park, NC 27711, telephone (919) 541-0880, e-mail at
morales.roberto@epa.gov,
Attention Docket ID No. OAR-2003-0053.

2. Tips for Preparing Your Comments. When submitting comments, remember to:

i. Identify the rulemaking by docket number and other identifying information (subject heading,
Federal Register
date and page number).

ii. Follow directions—The agency may ask you to respond to specific questions or organize comments by referencing a Code of Federal Regulations (CFR) part or section number.

iii. Explain why you agree or disagree; suggest alternatives and substitute language for your requested changes.

iv. Describe any assumptions and provide any technical information and/or data that you used.

v. If you estimate potential costs or burdens, explain how you arrived at your estimate in sufficient detail to allow for it to be reproduced.

vi. Provide specific examples to illustrate your concerns, and suggest alternatives.

vii. Explain your views as clearly as possible, avoiding the use of profanity or personal threats.

viii. Make sure to submit your comments by the comment period deadline identified.

II. Regulated Entities

This action does not propose to directly regulate emissions sources. Instead, it proposes to require States to revise their SIPs to include control measures to reduce emissions of NO
X
and SO
2
. The proposed emissions reductions requirements that would be assigned to the States are based on controls that are known to be highly cost effective for EGUs.

III. Website for Rulemaking Information

The EPA has also established a web site for this rulemaking at
http://www.epa.gov/interstateairquality/
which will include the rulemaking actions and certain other related information that the public may find useful.

IV. Public Hearing

The EPA will hold a public hearing on today's proposal on June 3, 2004. The hearing will be held at the following location: Holiday Inn Select, Old Town Alexandria, 480 King Street, Alexandria, Virginia 22314, Telephone: (703) 549-6080.

The public hearing will begin at 9 a.m. and continue until 5 p.m., or later if necessary depending on the number of speakers. Oral testimony will be limited to 5 minutes per commenter. The EPA encourages commenters to provide written versions of their oral testimonies either electronically (on computer disk or CD-ROM) or in paper copy. Verbatim transcripts and written statements will be included in the rulemaking docket. If you would like to present oral testimony at the hearing, please notify Joann Allman, U.S. EPA, Office of Air Quality Planning and Standards, C539-02, Research Triangle Park, NC 27711, telephone (919) 541-1815, email
allman.joann@epa.gov
, by May 31, 2004. For updates and additional information on the public hearing please check EPA's website for this rulemaking.

The public hearing will provide interested parties the opportunity to present data, views, or arguments concerning the proposed rule. The EPA may ask clarifying questions during the oral presentations, but will not respond to the presentations or comments at that time. Written statements and supporting information submitted during the comment period will be considered with the same weight as any oral comments and supporting information presented at a public hearing.

Outline

I. Background

II. State-by-State Emissions Reduction Requirements and EGU Budgets

A. SO
2
Emissions Budgets

B. NO
X
Emissions Budgets

III. Integration With Clean Air Act Programs

A. SIP Criteria

B. What Changes are EPA Proposing for Emissions Reporting Requirements?

C. Acid Rain Program

D. NO
X
SIP Call

E. How Would Emissions Trading Under This Proposed Rule Relate to Regional Haze?

F. Tribal Issues

IV. Model Cap-and-Trade Rules

A. Background and Purpose of the Model Rules

B. Elements of the Proposed NO
X
and SO
2
Model Trading Rules, Subparts AA through HH and AAA through HHH

V. Clarifications to January 30, 2004 Proposal

A. Scope of the Proposed Action

B. Summary of Control Costs

C. Source of Cost Information

D. Judicial Review Under Clean Air Act Section 307

VI. Statutory and Executive Order Reviews

VII. Proposed Rule Text

I. Background

The EPA's January 30, 2004 proposal (69 FR 4566-4650)
1

proposed to find that emissions of SO
2
and NO
X
from 28 States and DC, and emissions of NO
X
alone from 25 States and DC, violate the provisions of CAA section 110(a)(2)(D) by contributing significantly to nonattainment downwind of, respectively, the annual PM2.5 and the 8-hour ozone national ambient air quality standards (NAAQS).

1
The EPA signed the January 30, 2004 proposal on December 17, 2003 and made it immediately available to the public on EPA's Web site at
http://www.epa.gov/interstateairquality.

As a result, EPA proposed to require SIP revisions containing measures to ensure that necessary emissions reductions are achieved. The EPA proposed SIP submittal deadlines and other aspects of the SIP submittals. Further, the January 2004 proposal identified the appropriate NO
X
and SO
2
emissions that each of the affected jurisdictions would be required to eliminate. The January 2004 proposal explained that the affected States could choose to control any sources they wish to achieve those emissions reductions, and generally discussed the methodologies for determining the

appropriate amount of emissions reductions on a State-by-State basis. The January 2004 proposal further explained that the emissions reductions may most cost effectively be achieved by controls on electric generating units (EGUs), and, in particular, through regionwide cap-and-trade programs for EGUs. Accordingly, the January 2004 proposal indicated the methods for determining the allowable amounts of SO
2
and NO
X
emissions from EGUs, and offered a sketch of the model cap-and-trade programs, which EPA would offer to administer, that States may choose to adopt.

This supplemental proposal fills in certain gaps in the January 2004 proposal and revises it or its supporting information in specific ways. This section of the SNPR provides background on this supplemental proposal and summarizes its contents.

Section II of the SNPR provides additional detail on establishing State emissions budgets (
i.e.
, emissions reduction requirements) on which we are requesting comment.

Section III discusses the interaction of the January 2004 proposal with existing CAA programs and requirements. It includes discussion of specific SIP criteria and emissions reporting requirements. It also discusses the interactions of the Clean Air Interstate Rule (CAIR) with the Acid Rain Program that also requires SO
2
and NO
X
emissions reductions—and the NO
X
SIP Call, which was a 1998 rulemaking that required States in the eastern U.S. to submit SIPs reducing NO
X
emissions to eliminate adverse impacts on the 1-hour ozone NAAQS. Section III also discusses the implications of the CAIR for compliance with regional haze requirements. It also discusses Tribal issues in more detail than was contained in the January 2004 proposal.

Section IV provides significant additional details concerning the EPA's model cap-and-trade program for EGUs.

Section V includes clarifications to the January 2004 proposal with respect to preamble language that was unclear, incomplete, inadvertently omitted, or inadvertently incorrect.

Section VI addresses the required statutory and executive order reviews for this SNPR.

Section VII lists the sections of proposed regulatory language that are included in today's supplemental proposal. (The January 2004 proposal was not accompanied by proposed regulatory language).

Under CAA section 307(d)(1)(J), the procedural requirements of section 307(d) apply to this proposal. In addition, under section 307(d)(1)(U), the Administrator is authorized to include any other actions as covered under section 307(d). The EPA is including the proposals in today's SNPR and in the January 2004 proposal under section 307(d)(1)(U). Therefore, section 307(d) applies to all components of the rulemaking of which this action is a component.

II. State-by-State Emissions Reductions Requirements and EGU Budgets

In the January 2004 proposal, EPA proposed methods for determining the SO
2
and NO
X
emission reduction requirements or budgets for each affected State. Today, EPA proposes corrections to the proposals in the NPR. Additional details are included in a technical support document.
2

2
See, “State Emission Budget Calculation Technical Support Document for the Proposed Clean Air Interstate Rule (May 2004).”

Also, in the January 2004 proposal, EPA proposed methods for determining regionwide budgets. Today, EPA is not proposing any revisions to this methodology. However, in this SNPR, EPA used updated heat input data to develop the regionwide NO
X
budgets, yielding a slight difference.

The choice of method to impose State-by-State emissions reduction requirements makes little difference in terms of the overall cost of the regionwide SO
2
and NO
X
reductions. Assuming that allowances can be freely traded, the cap-and-trade framework would encourage least-cost compliance over the entire region, an outcome that does not depend on the relative levels of individual State budgets.

A. SO
2
Emissions Budgets

1. Approaches for Integrating SO
2
Title IV Program with CAIR

As described in the January 2004 proposal and other places in today's preamble, EPA is proposing to integrate the title IV Acid Rain SO
2
program with the trading program proposed in today's notice by requiring facilities to comply with this rule using title IV allowances at a greater retirement ratio than one allowance for every one ton of emissions. In the January 2004 proposal, EPA proposed that, to meet the 65 percent reduction required under Phase II (which begins in 2015), EPA could require an affected EGU to retire three 2015 and beyond allowances for every ton of SO
2
that it emits. However, this 3-to-1 ratio results in slightly more reductions than EPA has proposed are necessary to eliminate the significant contribution of an upwind State. This section of today's SNPR proposes two basic alternatives for addressing this issue.

Under the first alternative EPA solicits comment on requiring affected EGUs to retire vintage 2015 and beyond title IV allowances at a rate of 2.86-to-1 rather than 3-to-1. This alternative effectively eliminates the difference between the proposed cap levels and the resulting reductions. The EPA solicits comment on the use of this retirement ratio and specifically on whether the use of a fractional retirement ratio (2.86-to-1 instead of 3-to-1) raises practical implementation concerns for States or affected EGUs or whether a fractional retirement ratio is preferable to the two-step process described below.

Alternatively, EPA proposes requiring the retirement of 2015 and beyond vintage allowances at a 3-to-1 ratio, and permitting States to convert these additional reductions into allowances in their rules. That is, the States would retain special “CAIR SO
2
allowances” equivalent to the difference between the 3-to-1 retirement ratio and the effective 2015 cap. Thus, an amount of allowances (assuming allowances would be retired at a 3-to-1 ratio) equivalent to three times the number that represents the margin of difference in the retirement ratio for 2015 would then be made available to States. Under this approach, these reserved allowances would be distributed to the States based on the same methodology used to distribute title IV allowances, and States would have flexibility to further distribute them however they deem appropriate. The States might choose, for example, to distribute them to EGUs using the same methodology that had been used for distributing the original title IV allowances, or use them as a set-aside for new sources or for sources that did not receive title IV allowances originally, or they might distribute them as incentives for achieving other policy goals each State may have.

Some States may want to use these reserved allowances to create an incentive for additional local emission reductions that will be needed to bring all areas into attainment with the PM2.5 NAAQS. The EPA projects that the proposed CAIR, along with other Federal and State programs already in place, will bring most areas of the country into attainment with the PM2.5 NAAQS by 2015 without the need for additional local controls. These regional and national programs, however, are not designed to deal with all local pollution problems, and we expect that there will be a small number of areas that will need additional local emissions reductions to reach attainment. In such cases, States could use their reserved

allowances to create an incentive for additional local reductions—perhaps by providing reserved allowances to affected EGUs based on their proposals for achieving additional reductions in areas that are projected to need further local emissions reductions to come into attainment with the PM2.5 NAAQS.

Mechanisms that States could use for allocating these reserved allowances could range from basic financial incentives to more aggressive and innovative approaches. In its simplest form, the EGUs could choose to complement or expand existing control measures, or perhaps fund new ones. Under the latter approach, a specific value could be applied to a ton of local emissions to be reduced depending on one or more specific criteria such as: The accuracy and technical validity of emissions monitoring used to characterize emissions or demonstrate compliance, seasonal timing or location of the reductions, population exposure, or other considerations.

For example, reducing PM2.5 from a sector in a nonattainment area might receive a greater allowance value than reductions from a sector that is downwind of the nonattainment area most of the year, due to the relative effectiveness of the measures at reducing population exposure and monitoring of PM2.5. Another example could be one in which the EGUs receive allowances in exchange for reductions in other pollutants causing PM2.5, based on using technically appropriate air quality models to demonstrate superior environmental results. Nevertheless, States would have discretion on whether and how to use any reserved allowances to achieve additional local emission reductions.

2. Proposed SO
2
State Emission Budget Methodology

a. Overview. In this section, EPA discusses the methodology for apportioning regionwide SO
2
emissions reductions requirements or budgets to the individual States. In the January 2004 proposal we proposed State EGU SO
2
budgets based on each State's allowances under title IV of the CAA Amendments with specified retirement ratios. This continues to be EPA's proposal for determining State SO
2
budgets. In addition, we discussed an alternate method of relying on Title IV allowances that would provide for some EGU allowances that could be redistributed to account for changes to the electric generation sector since the title IV allocations were created (using a two-part budget methodology). In this SNPR, EPA identifies some problems with the two-part method as described in the January 2004 proposal, withdraws the January 2004 proposal on this point, and is re-proposing that all States use the same retirement ratios for Title IV allowances.

b. NPR discussion. The EPA discussed its proposed SO
2
emission budget methodology at length in the January 2004 proposal. In that discussion, EPA outlined the various reasons for tying the SO
2
requirements of the proposed CAIR to the title IV program. Without carefully integrating the CAIR and title IV programs, emissions may increase prior to implementation of the CAIR and emissions may shift to outside the control region. In addition, because the regulated community has relied on the title IV program in the past, and is planning on continued reliance for the future, lack of integration could give rise to concerns about the stability of EPA's regulatory efforts and the accompanying allowance market.

Under the approach proposed for SO
2
, the State budgets would be based on the initial allocation of allowances to individual sources established by title IV of the 1990 CAA Amendments. The budgets are shown in Table II-1, revised to correct a slight calculation error in the January 2004 proposal,
3

as explained in the technical support document.
4

3
As in the SO
2
State budgets included in the January 2004 proposal, these budgets include the 250,000 allowances in the Special Allowance Reserve, prorated to the individual States in proportion to the sum of the 2010 individual units allocations for the State.

4
See, “State Emission Budget Calculation Technical Support Document for the Proposed Clean Air Interstate Rule (May 2004).”

Table II-1.—28-State and District of Columbia Annual EGU SO
2
Budgets

State

28-State SO
2
Budget 2010
(tons)

28-State SO
2
Budget 2015
(tons)

Alabama
157,582
110,307

Arkansas
48,702
34,091

Delaware
22,411
15,687

District of Columbia
708
495

Florida
253,450
177,415

Georgia
213,057
149,140

Illinois
192,671
134,869

Indiana
254,599
178,219

Iowa
64,095
44,866

Kansas
58,304
40,812

Kentucky
188,773
132,141

Louisiana
59,948
41,963

Maryland
70,697
49,488

Massachusetts
82,561
57,792

Michigan
178,605
125,024

Minnesota
49,987
34,991

Mississippi
33,763
23,634

Missouri
137,214
96,050

New Jersey
32,392
22,674

New York
135,139
94,597

North Carolina
137,342
96,139

Ohio
333,520
233,464

Pennsylvania
275,990
193,193

South Carolina
57,271
40,089

Tennessee
137,216
96,051

Texas
320,946
224,662

Virginia
63,478
44,435

West Virginia
215,881
151,117

Wisconsin
87,264
61,085

Total Regional Budget
3,863,566
2,704,490

Note: As explained in the proposed January 2004 proposal (69 FR 4618) the regionwide budgets for the years 2010-2014 are based on a 50 percent reduction from title IV allocations for all units in affected States. The regionwide budget for 2015 and beyond is based on a 65 percent reduction.

c. Problems with the methodology proposed in the NPR. In the Model Trading section of the January 2004 proposal, EPA proposed giving States the option of deciding whether to adopt a two-part budget approach, making available additional SO
2
allowances through the use of higher retirement ratios (69 FR 4620,4632). However, upon further assessment, it has become evident that problems could arise if various States implemented this approach differently. Specifically, the level of the regional cap on SO
2
emissions could increase or decrease, depending on which individual States tightened the retirement ratios.

An example could best illustrate this point. Assume State A in the proposed CAIR region has a State SO
2
budget of 300,000 tons in 2010, reflecting a 50 percent reduction from its 600,000 2010 title IV SO
2
allowances. Assume also that State A decides to implement a 3-to-1 retirement ratio for its 600,000 title IV SO
2
allowances in 2010, but all other States in the proposed CAIR region continue requiring 2-to-1 retirement ratios. Assume further that EPA allocates State A additional CAIR allowances for 100,000 tons of emissions, which reflect the difference between State A's 3-to-1 retirement ratio (200,000 tons) and the overall 2-to-1 retirement ratio (300,000 tons). With one CAIR allowance equivalent to one title IV allowance, State A, with its 3-to-1 ratio, would thus receive 300,000 CAIR allowances. Assume that State A allocates all of these new CAIR allowances to its sources. To illustrate most vividly the problem that may result, assume the extreme case in which State A's emissions in 2010 approach zero (due to efficiencies in implementing controls or lower generation levels) and therefore that its sources sell all their title IV allowances as well as its additional CAIR allowances to sources in other States. In this example, the total amount of State A's allowances (600,000 title IV allowance plus 300,000 CAIR allowances) would be available for complying with the 2-to-1 ratio required by the other States. Consequently, the additional CAIR allowances allocated by EPA would effectively raise the overall regional cap by 150,000 tons, reflecting the 300,000 CAIR allowances retired at a 2-to-1 ratio.

To illustrate how this same case could lead to the opposite problem of a lower regional cap, assume that State A's emissions were to remain very high or to increase, so that its sources purchase allowances from other States and then retire them at a 3-to-1 ratio in 2010. State A sources would have to purchase more allowances than the amount State A had redistributed as additional CAIR allowances. This would mean the total amount of allowances for 2010, and thus the total regional cap, would in effect be lower.

In fact, in these examples, in any year that State A's emissions are not exactly one-third of their title IV allocations, the level of the overall regional cap would be impacted. This lack of certainty about the cap is unacceptable for a cap-and-trade program, as it undermines both the environmental certainty and economic stability of the program. Therefore, EPA is withdrawing the January 2004 proposal on this point and re-proposing that all States use the same retirement ratio.

3. SIP Approvability

In section III.A, EPA outlines the proposed SIP approvability criteria if EPA adopts a requirement to retire allowances at ratios of greater than 1-to-1. Specifically, (1) all States must use the same retirement ratios whether or not they participate in the trading program and whether or not they achieve all the required emissions reductions through controls on EGUs, (2) if a State does not require all of the emissions reductions through requirements on EGUs, they may create extra CAIR allowances which would be calculated by multiplying the reductions required from the other sources by the required retirement ratio for that given year, and (3) the overall reduction requirement for a State would be set at the difference between a State's 2010 title IV allowance allocations and the EPA-determined CAIR SO
2
State budgets for the two phases. Please note, as described in section IV, that if a State chooses to achieve emissions reductions from non-EGUs, then that State's EGUs may not participate in the EPA administered cap-and-trade program.

B. NO
X
Emissions Budgets

1. Overview

In this section, EPA discusses the apportioning of proposed regionwide NO
X
emission reduction requirements or budgets to the individual States. In the January 2004 proposal we proposed State EGU NO
X
budgets based on each State's average share of recent historic heat input. In today's SNPR, we propose the same heat input based methodology, but we propose revised budgets based on more complete heat input data.

In addition to the proposed heat input based method, in this SNPR we also discuss a different approach suggested by commenters for apportioning regionwide NO
X
budgets to the States. As discussed in section IV of this SNPR, we propose that States have the discretion in choosing a methodology to distribute allowances from their NO
X
budgets to individual sources.

2. NO
X
Emission Budget Methodology Proposed in the NPR

a. NPR discussion. In the January 2004 proposal, we proposed annual NO
X
budgets for a 28-State (and D.C.) region based on each jurisdiction's average heat input—using heat input data from Acid Rain Program units—over the years 1999 through 2002. We summed the average heat input from each of the applicable jurisdictions to obtain a regional total average annual heat input. Then, each State received a pro rata share of the regional NO
X
emissions budget based on the ratio of its average annual heat input to the regional total average annual heat input.

b. Today's revised proposal. In this SNPR, the use of average heat inputs is still our preferred approach. However, State budgets based on heat input data

from Acid Rain Program units only would not reflect the heat input of non-Acid Rain units. For example, a State with a large number of non-Acid Rain units would not have the heat input from those units reflected in the percent of regional average annual heat input that the State's generation represents. Therefore, today EPA proposes to revise its determination of State NO
X
budgets by supplementing Acid Rain Program unit data with annual heat input data from the U.S. Energy Information Administration (EIA), for the non-Acid Rain unit data. Table II-2 contains the proposed revised annual State NO
X
budgets. Note that the Acid Rain Program data for 2002 has been updated since our analysis for the January 2004 proposal was completed and was included in the calculation of these budgets.

Table II-2.—28-States and District of Columbia Annual EGU NO
X
Budgets—Based on Heat Input

State

State NO
X
Budget 2010
(tons)

State NO
X
Budget 2015
(tons)

Alabama
67,422
56,185

Arkansas
24,919
20,765

Delaware
5,089
4,241

District of Columbia
215
179

Florida
115,503
96,253

Georgia
63,575
52,979

Illinois
73,622
61,352

Indiana
102,295
85,246

Iowa
30,458
25,381

Kansas
32,436
27,030

Kentucky
77,938
64,948

Louisiana
47,339
39,449

Maryland
26,607
22,173

Massachusetts
19,630
16,358

Michigan
60,212
50,177

Minnesota
29,303
24,420

Mississippi
21,932
18,277

Missouri
56,571
47,143

New Jersey
9,895
8,246

New York
52,503
43,753

North Carolina
55,763
46,469

Ohio
101,704
84,753

Pennsylvania
84,552
70,460

South Carolina
30,895
25,746

Tennessee
47,739
39,783

Texas
224,314
186,928

Virginia
31,087
25,906

West Virginia
68,235
56,863

Wisconsin
39,044
32,537

Total Regional Budget
1,600,799
1,333,999

Note:

NO
X
control requirements for Connecticut were discussed in the January 2004 proposal.

Commenters have also suggested adjusting the heat input data for existing units used to determine State budgets by multiplying it by different factors, established regionwide based on fuel type. The factors would reflect the inherently higher emissions rate of coal-fired plants, and consequently the greater burden on coal plants to control emissions. In contrast to allocations based on historic emissions, the factors would also not penalize coal-fired plants that have already installed pollution controls. States shares would be determined by the amount of State heat input, as adjusted, in proportion to the total regional heat input. The factors could be based on average historic emissions rates (in lbs/mmBtu) by fuel type (coal, gas, and oil) for the years 1999-2002.

The EPA also discussed in the January 2004 proposal a methodology used in the NO
X
SIP Call (67 FR 21868) that applied State-specific growth rates for heat input in setting State budgets. With a methodology similar to that used in the NO
X
SIP Call, annual NO
X
budgets would be set by using a base heat input data, then adjusting it by a calculated growth rate for each jurisdiction's annual EGU heat inputs. The EPA is not proposing to use this method for the CAIR because we believe that the other methods that we are proposing (or taking comment on) are more reasonable due to the inherent difficulties in predicting growth in heat input over a lengthy period, especially for jurisdictions that are only a part of a larger regional electric power dispatch region.

III. Integration With Clean Air Act Programs

This section details how the rules that States develop to meet the requirements of the proposed CAIR must be structured to conform with CAA programs. It proposes: Specific criteria that SIPs submitted to meet the requirements of the proposed CAIR must meet; emissions inventory reporting requirements; revisions to the title IV Acid Rain regulations to integrate them with the proposed CAIR emissions trading programs; requirements to ensure that requirements of the existing NO
X
SIP Call continue to be met; that BART-eligible EGUs in any State affected by CAIR may be exempted from BART if that State complies with the CAIR requirements through adoption of the CAIR cap-and-trade program for SO2 and NO
X
emissions. Finally, this section

provides additional discussion on the implications of the CAIR for tribes.

A. SIP Criteria

1. Introduction

This section describes (1) the dates for submittal and implementation of the SIPs that we propose to require under the CAIR, and (2) the criteria we propose to use in determining completeness and approvability of such SIPs.

2. Schedule for Submission and Implementation of SIPs

a. SIP submission schedule. In the January 2004 proposal, EPA proposed that States must submit the SIP revisions required under the CAIR as expeditiously as practicable but no later than 18 months from the date of promulgation of the final rule. The proposed regulatory text at the end of this SNPR, 40 CFR 51.123 (for NO
X
emissions) and 40 CFR 51.124 (for SO2 emissions), contains this proposed submittal date.

b. Implementation Schedule. In the January 2004 proposal, EPA proposed that States must implement the control measures in their CAIR SIP revisions by January 1, 2010. The proposed regulatory text at the end of this SNPR, 40 CFR 51.123 (for NO
X
emissions) and 40 CFR 51.124 (for SO
2
emissions), contains this proposed implementation date.

i. Relationship to attainment dates. On April 15, 2004, the Administrator signed a rule to designate and classify areas under the 8-hour ozone NAAQS. (69 FR 23858, April 30, 2004). Under the CAA, all areas designated as nonattainment are required to come into attainment with the NAAQS “as expeditiously as practicable.” In addition, specific maximum attainment dates apply to different areas depending on their classification. In the Eastern U.S., all 8-hour ozone areas are classified as subpart 1 areas, marginal areas, or moderate areas. For subpart 1 areas, the attainment date is no later than June 2009, although EPA can extend this date by up to five years based on certain statutory criteria. The attainment dates for marginal and moderate areas are June 2007 and June 2010, respectively. State implementation plans must achieve reductions required for attainment by the beginning of the complete ozone season prior to the attainment date (e.g., the 2009 ozone season for moderate areas).

In response to the January 2004 proposal, some commenters have expressed concern that the CAIR compliance dates (January 1, 2010, for Phase I, and January 1, 2015, for Phase 2) come too late for Eastern States to meet their deadlines for coming into attainment with the 8-hour ozone NAAQS. In making ozone designations, however, EPA recognized that certain areas may find it difficult to adopt plans showing attainment by their initial attainment dates, and would choose to be reclassified to higher classifications with longer attainment dates. For example, an area reclassified to serious would have a June 2013 attainment deadline, and would be required to achieve reductions required for attainment by the 2012 ozone season. It is also possible that some subpart 1 areas will qualify for an extension and receive an attainment date later than June 2009. In addition, an area failing to attain on time can qualify for up to two one-year extensions if it meets statutory criteria. Therefore, CAIR implementation by the 2013 or 2014 ozone season could facilitate attainment by a serious area receiving one-year extensions.

Some commenters also asserted that a similar timing issue arises for PM2.5. Assuming PM2.5 designations by the statutory deadline of December 2004, the PM2.5 attainment deadlines would be no later than early 2010, or no later than early 2015 for areas receiving a maximum 5-year extension. To influence whether an area attains by those dates, reductions would have to occur one to three years earlier. Because of the structure of the proposed program, which creates a strong financial incentive for early reductions, EPA projects substantial early reductions in SO
2
. Thus, although the Phase I cap does not come into place until 2010, the proposed program would achieve substantial reductions in SO
2
emissions. In addition, the same opportunity for one-year extensions mentioned for ozone exists for PM2.5 areas.

In light of the discussion above, EPA requests comment on all aspects of the issues concerning the timing of the proposed CAIR compliance dates in relation to NAAQS attainment dates.

ii. Implementation date and beginning of calendar year. The EPA believes that it is most straightforward for EPA to develop and implement the requirements of the proposed CAIR, for sources to comply with the proposed CAIR, and to ensure the environmental effectiveness of the proposed CAIR, if the compliance date for sources is the beginning of a calendar year (or for requirements that pertain only to ozone, at the beginning of the ozone season). There are several reasons for this approach. First, the proposed requirements for States are annual emissions reductions. Beginning the program at any point other than the start of a calendar year would require the development and implementation of different Federal requirements for the first year of the program.

Second, different State rules to meet these requirements would also be necessary for the first, partial year portion of a program. States would have to develop partial year allocations. Additionally, States would have to modify monitoring and reporting requirements to address partial year reporting. Further, for SO
2
emissions reductions requirements, because of the interactions with title IV (which is an annual program), provisions would be needed to address both the annual requirements of title IV and the partial year requirements of the CAIR.

For these administrative feasibility reasons, EPA proposes that the emissions reductions requirements begin at the start of the calendar year, and not at any other time during a calendar year. However, EPA solicits comment on the administrative feasibility issues of implementing these requirements on a partial year basis for the first year of the program.

In particular, EPA solicits comment on the appropriate budget allocation method, and, to promote discussion, offers the following observations for both NO
X
and SO
2
partial year budgets. For the NO
X
EGU emissions budget, partial year allocation could be accomplished by pro-rating to account for the fact that the program would be implemented for less than a full year. The simplest method would be to pro-rate by the number of days that the program would be implemented. For example, if the program began on January 31, 2010, budgets would be pro-rated by the factor 335/365, where 335 equals the number of days in the year in which States will be required to comply with the program.

At least in theory, more complex methodologies could be developed to account for the fact that the amount of generation—and therefore the amount of NO
X
emissions—varies throughout the year (
e.g.,
in many areas, summer generation is higher due to air conditioning load; in other areas that are heavily dependent on hydro power, fossil-fuel generation can vary seasonally with availability of hydro power). However, because factors that affect peak generation vary by region, EPA believes it would be very difficult to develop a methodology that reasonably addresses these many variations. Therefore, we believe that

the simplest pro-rata methodology described above would be appropriate for a partial year allocation.

Budgets for SO
2
could be set in a similar way. A State's SO
2
budget could be pro-rated by the number of days that the program would be in place. Because of the interactions with title IV (an annual program), implementation of a partial year budget for SO
2
would be somewhat more complicated. For emissions from the first portion of the year in which the State was not required to comply with the CAIR, the Acid Rain sources would still be subject to the 1-to-1 retirement ratio required under title IV. For emissions from the second part of the year, all EGUs affected by the CAIR would be required to turn in allowances of that vintage year at a ratio of 2-to-1.

3. Completeness Determination

Any SIP submittal that is made with respect to the final CAIR requirements first would be determined to be either incomplete or complete. A finding of completeness means that EPA would proceed to review the submittal to determine whether it is approvable. It is not a determination that the submittal is approvable; rather, it means the submittal is administratively and technically sufficient for EPA to determine whether it meets the statutory and regulatory requirements for approval. Under 40 CFR 51.123 and 40 CFR 51.124 (the proposed new regulations for NO
X
and SO
2
SIP requirements, respectively), a submittal, to be complete, must meet the criteria described in 40 CFR, part 51, appendix V, “Criteria for Determining the Completeness of Plan Submissions.” These criteria apply generally to SIP submissions.

Under CAA section 110(k)(1) and section 1.2 of appendix V, EPA must notify States whether a submittal meets the requirements of appendix V within 60 days of, but no later than 6 months after, EPA's receipt of the submittal. If a completeness determination is not made within 6 months after submission, the submittal is deemed complete by operation of law. For rules submitted in response to the CAIR, EPA intends to make completeness determinations expeditiously. In addition, if a State fails to make any submission by the required submission date, EPA expects to make a finding of failure to submit within the same period that would apply to making a completeness determination had a SIP been submitted on time.

A finding of failure to submit or incompleteness triggers the requirement that EPA promulgate a Federal implementation plan (FIP) within 2 years of the date of the finding. In addition, if a complete SIP is submitted in a timely fashion but EPA disapproves it, the requirement to promulgate a FIP within 2 years would be triggered by EPA's disapproval. The EPA's obligation to promulgate a FIP in either instance would terminate upon EPA's approval of a SIP as meeting the requirements of the CAIR.

4. Approvability Criteria

a. Introduction. The approvability criteria for CAIR SIP submissions appear in the proposed 40 CFR 51.123 (NO
X
emissions reductions) and in the proposed 40 CFR 51.124 (SO
2
emissions reductions). Most of the criteria are substantially similar to those that currently apply to SIP submissions under CAA section 110 or part D (nonattainment). For example, each submission must describe the control measures that the State intends to employ, identify the enforcement methods for monitoring compliance and handling violations, and demonstrate that the State has legal authority to carry out its plan.

This part of the section III preamble explains additional approvability criteria specific to the CAIR that were proposed in the January 2004 proposal, or are being proposed in today's SNPR. As explained in the January 2004 proposal, EPA proposed that each affected State must submit SIP revisions containing control measures that assure a specified amount of NO
X
and SO
2
emissions reductions by specified dates.

Although EPA determined the required amount of emissions reductions by identifying specified control levels for EGUs that are highly cost effective, EPA explained in the January 2004 proposal that States have flexibility in choosing the sources to control in order to achieve the required emissions reductions. As long as the State's emissions reductions requirements are met, a State may impose controls on EGUs only, on non-EGUs only, or on a combination of EGUs and non-EGUs. The EPA's proposed SIP approvability criteria are intended to provide as much certainty as possible that, whichever sources a State chooses to control, the controls will result in the required amount of emissions reductions.

In the January 2004 proposal, EPA proposed a “hybrid” approach for the mechanisms used to ensure emissions reductions from sources. This approach incorporates elements of an emissions “budget” approach (requiring an emissions cap on affected sources) and an “emissions reductions” approach (not requiring an emissions cap). In this hybrid approach, if States impose control measures on EGUs, they would be required to impose an emissions cap on all EGUs, which would effectively be an emissions budget. However, as stated in the January 2004 proposal, if States impose control measures on non-EGUs, they would be encouraged but not required to impose an emissions cap on non-EGUs. In the January 2004 proposal, we requested comment on the issue of requiring States to impose caps on any source categories the State chooses to regulate.

Today, we propose to modify this hybrid approach so that States choosing to impose control measures on large industrial boilers and/or turbines must do so by imposing an emissions cap on all such sources within their State. This is similar to EPA's approach in the NO
X
SIP Call which required States to include an emissions cap on such sources as well as on EGUs if the SIP submittals included controls on such sources. (See 40 CFR 51.121(f)(2)(ii), referenced at 63 FR 57494, October 27, 1998.)

Below, EPA describes specific criteria, depending on which sources States choose to control.

b. Requirements if States Choose To Control EGUs.

i. Emissions caps. As explained in the January 2004 proposal (69 FR 4626), EPA proposed that States must apply the “budget” approach if they choose to control EGUs; that is, States must cap EGU emissions at the level that assures the appropriate amount of reductions. These caps constitute the State EGU budgets for SO
2
and NO
X
. Additionally, EPA proposed that, if States choose to control EGUs, they must require EGUs to follow part 75 monitoring, recordkeeping, and reporting requirements.

If States choose to allow their EGUs to participate in EPA-administered interstate NO
X
and SO
2
emissions trading programs, States must adopt EPA's model trading rules, as described in section IV below and as proposed in 40 CFR part 96, § 96.101-§ 96.176 and § 96.201-§ 96.276, below. States adopting EPA's model trading rules, with only those modifications specifically allowed by EPA, will meet the requirements for applying an emissions cap as well as part 75 monitoring, recordkeeping, and reporting requirements to EGUs.

If States choose to control EGUs but not to allow them to participate in EPA-administered NO
X
and SO
2
emissions trading programs, States must still impose an emissions cap as well as part

75 monitoring, recordkeeping, and reporting requirements on all EGUs. Additionally, States must use the same definition of EGU as EPA uses in its model trading rules,
i.e.
, the sources described as “CAIR units” in proposed 40 CFR 96.102 and 40 CFR 96.202. If a State chooses to design its own NO
X
and SO
2
emissions trading programs, regardless of whether they are for intrastate or interstate trading, in addition to meeting the requirements of these rules, they should consider EPA's guidance, “Improving Air Quality with Economic Incentive Programs,” January 2001 (EPA-452/R-01-001) (available on EPA's Web site at:
http://www.epa.gov/ttn/ecas/incentiv.html)
, and the rules must be approved by EPA. It should be noted that EPA would not administer a State-designed program, so the State (or States) would need to administer such programs.

ii. Retirement Ratios. The January 2004 proposal required each State to assure that the title IV SO
2
allowances for vintage year 2010 and beyond for the State's EGUs that exceed the State's CAIR EGU SO
2
emissions budget cannot be used in a manner that would lead to emissions increases in areas not affected by the CAIR. Additionally, EPA was concerned that a devaluation of title IV allowances (because of the more stringent requirements of the CAIR) could lead to emissions increases prior to implementation of the CAIR. The EPA's concerns regarding these allowances are described in the January 2004 proposal at 69 FR 4630. To avoid these significant problems, the January 2004 proposal in effect would require the State to include a mechanism for retirement of the allowances in excess of the State's budget.

The number of retired allowances must be at least equal to the difference between the number of title IV allowances allocated to EGUs in a State and the SO
2
budget the State sets for EGUs under this rule. This requirement to retire allowances in excess of a State's budget applies regardless of whether or not a State participates in the EPA-administered trading programs. If a State chooses to participate in the EPA-administered trading programs, the State must follow the provisions of the model trading rules, described in section IV below, that require that vintage 2010 through 2014 title IV allowances be retired at a ratio of 2 allowances for every ton of emissions and that vintage 2015 and beyond title IV allowances be retired at a ratio of three allowances for every ton of emissions. Pre-2010 vintage allowances would be retired at a ratio of one allowance for every ton of emissions. (See section IV.B.1 of this SNPR.)

In the January 2004 proposal, EPA stated that if a State does not choose to participate in the EPA-administered trading programs, the State may choose the specific method to retire allowances in excess of its budget. The EPA has further considered alternative ways for retiring these excess allowances and believes that if different States use different means to address this concern, it could undermine the regionwide emission reduction goals of the proposed CAIR. The EPA's concerns are further described in Section II of today's preamble. Because of these concerns, EPA is withdrawing the January 2004 proposal on this point and re-proposing that all States use a 2-for-1 retirement ratio for vintage 2010 through 2014 allowances and a 3-for-1 retirement ratio for vintage 2015 allowances and beyond to address concerns about title IV allowances that exceed State budgets.

State rules may also allow sources currently subject to title IV and to the NO
X
SIP Call trading program to use allowances banked from those programs before 2010 for compliance with the CAIR, provided that States which participate in EPA's CAIR trading programs must allow this, in accordance with EPA's model trading rules. For further discussion of banking of NO
X
SIP Call allowances, see the January 2004 proposal (69 FR 4633).

c. Requirements if States Choose to Control Sources Other Than EGUs

i. Overview of requirements. As noted in the January 2004 proposal, if a State chooses to require emissions reductions from non-EGUs, the State must adopt and submit SIP revisions and supporting documentation designed to quantify the amount of reductions from the non-EGU sources and to assure that the controls will achieve that amount. Although EPA did not propose that States be required to impose an emissions cap on those sources but instead solicited comment on the issue, EPA proposes today that States be required to impose an emissions cap in certain cases on non-EGU sources.

If a State chooses to obtain some but not all of its required emissions reductions from non-EGUs, it would still be required to set an EGU SO
2
budget and/or an EGU NO
X
budget, but at some level higher than shown in Tables VI-9 and VI-10 in the January 2004 proposal (69 FR 4619-4620), thus allowing more emissions from its EGUs. The difference between the amount of a State's SO
2
EGU budget in Table VI-9 and a State's selected higher EGU SO
2
budget would be the amount of SO
2
emissions reductions the State must demonstrate it will achieve from non-EGU sources. By the same token, the difference between the amount of a State's NO
X
EGU budget in Table VI-10 and a State's selected higher EGU NO
X
budget would be the amount of NO
X
emissions reductions the State must demonstrate it will achieve from non-EGU sources.

If States require SO
2
emissions reductions from non-EGU sources, States should still use the same retirement ratio (
i.e.
, 2-for-1 for vintage 2010 through 2014 allowances and 3-for-1 for vintage 2015 allowances and beyond) for title IV allowances. To account for the fact that the State is not requiring its EGUs to reduce as much, the State can allocate additional allowances. The number of these allowances will be calculated by multiplying the emissions reductions required for the non-EGU source category by the title IV retirement ratio.

The demonstration of emissions reductions from non-EGUs is a critical requirement of the SIP revision due from a State that chooses to control non-EGUs. As noted in the January 2004 proposal, the State must take into account the amount of emissions attributable to the source category in both (i) the base case, in the implementation years 2010 and 2015,
i.e.
, without assuming SIP-required reductions from that source category under the final CAIR, and (ii) in the control case, in the implementation years 2010 and 2015,
i.e.
, with assuming SIP-required reductions from that source category under the CAIR SIP. We are proposing an alternative methodology for calculating the base case for certain large non-EGU sources, as described below, but generally the difference between emissions in the base case and emissions in the control case equals the amount of emissions reductions that can be claimed from application of the controls on non-EGUs. (See below for criteria applicable to development of the baseline and projected control emissions inventories.)

Additionally, if a State chooses to obtain some or all of its required emission reductions from non-EGUs, EGUs in that State could not participate in the EPA administered multi-State trading programs.

ii. Eligibility of non-EGU reductions. In evaluating whether emissions reductions from non-EGUs would count towards the emissions reductions required under the CAIR, States may include only reductions attributable to measures that are not otherwise required under the CAA. This exclusion

of credit is consistent with the NO
X
SIP Call. For the most part, the measures that are mandated by the CAA, and that EPA proposes be excluded from credit towards the emission reduction requirements of the CAIR, were assumed to be in place in the emissions projections and air quality contribution analysis used in the proposed findings regarding significant contribution to nonattainment in 2010.
5

5
The 2010 emissions projections did not account for requirements for reasonably available control technology (RACT), reasonably available control measures (RACM), and vehicle inspection/maintenance in any new 8-hour ozone or PM2.5 nonattainment areas, as these areas had not been designated at the time of the modeling. However, we believe that not accounting for these requirements did not distort the proposed findings for each State because the aggregate reductions in NO
X
and SO
2
emissions from these measures would be at most a small percentage of overall emissions.

Specifically, States must exclude reductions attributable to measures otherwise required by the CAA, including: (1) Measures already in place at the date of promulgation of the final CAIR, such as adopted State rules, SIP revisions approved by EPA, and settlement agreements; (2) measures adopted and implemented by EPA (or other Federal agencies) such as emissions reductions required pursuant to the Federal Motor Vehicle Control Program for mobile sources (vehicles or engines) or mobile source fuels, or pursuant to the requirements for National Emissions Standards for Hazardous Air Pollutants; and (3) specific measures that are mandated under the CAA (which may have been further defined by EPA rulemaking) based on the classification of an area which has been designated nonattainment for a NAAQS, such as vehicle inspection and maintenance programs. If a State can demonstrate that a new or modified measure is more stringent than what is required, e.g., due to broader geographic coverage or more stringent emissions reductions levels, the State may count toward the CAIR requirement the reductions attributable to the more stringent requirement. The exclusion of credit for ineligible measures is accomplished by including those measures in both the base and control cases, if they have already been adopted; or by excluding them from both the base and control cases if they have not yet been adopted.

States required to make CAIR SIP submittals may also be required to make other SIP submittals to meet other requirements applicable to non-EGUs, e.g., nonattainment SIPs required for areas designated nonattainment under the PM2.5 or 8-hour ozone NAAQS. These SIPs could include, for example, measures to be adopted such as Reasonably Available Control Technology (RACT) measures pursuant to CAA section 182.

It is likely that CAIR SIP submittals will be due before or at the same time that some of these other SIP submittals are due. States relying on reductions from controls on non-EGUs must commit in the CAIR SIP revisions to replace the emissions reductions attributable to any CAIR SIP measure if that measure is subsequently determined to be required in meeting any other SIP requirement related to adoption of control measures. The State could make this replacement by decreasing its EGU emissions cap or a non-EGU emissions cap, if applicable, by the appropriate amount.

iii. Emissions controls and monitoring. As noted above, we are modifying the “hybrid” approach described in the January 2004 proposal as it applies to non-EGUs. For States that choose to impose controls on certain non-EGUs, namely large industrial boilers and turbines, i.e., those whose maximum design heat input is greater than 250 mmBtu/hr, to meet part or all of their emissions reductions requirements under the CAIR, EPA proposes that State requirements must include an emissions cap on all such sources in their State. Additionally, EPA proposes that in this situation, States must require those large industrial boilers and turbines to meet part 75 requirements for monitoring and reporting emissions as well as recordkeeping. The EPA proposes that if a State chooses to control non-EGUs other than large industrial boilers and turbines to obtain the required emissions reductions, the States must either (i) impose the same requirements, i.e., an emissions cap on all the non-EGUs in the source category and Part 75 monitoring, reporting and recordkeeping requirements, or (ii) must demonstrate why such requirements are not practicable. In the latter case, the State must adopt appropriate alternative requirements to ensure to the maximum practicable degree that the required emissions reductions will be achieved. Further, if a State adopts alternative requirements that do not apply to all non-EGUs in a particular source category (defined to include all sources where any aspect of production is reasonably interchangeable), the State must demonstrate that it has analyzed the potential for shifts in production from the regulated sources to lesser regulated sources in the same State as well as in other States, and that the State is not including reductions attributable to sources that may shift emissions to such non-regulated or not as stringently regulated sources.

iv. Emissions inventories and demonstrating reductions. Quantifying emissions reductions attributable to controls on non-EGUs requires that the States submit both baseline and projected control emissions inventories for the applicable implementation years. We have issued many guidance documents and tools for preparing such emissions inventories, some of which apply to specific sectors States may choose to control. While much of that guidance is applicable to the proposed CAIR, there are some key differences between quantification of emission reduction requirements under a SIP designed to help achieve attainment with a NAAQS and emission reduction requirements under a SIP designed to reduce emissions that contribute to a downwind State's nonattainment problem. When addressing its own nonattainment problem, a State has an incentive not to overestimate emission reductions. If a State overestimates emission reductions, the potential consequence is that the State would remain out of attainment. Missing an attainment deadline has adverse impacts upon a State. Among other things, the area may be “bumped up” to a higher classification with more stringent requirements.

Under transport requirements, however, overestimating emission reductions has fewer intrastate consequences (because it is the downwind State that would pay the price of remaining in nonattainment). For this reason, EPA believes that it is appropriate to have more stringent guidelines with respect to quantification of emission reductions under a program designed to reduce transported pollutants than are currently used with respect to SIPs addressing intrastate air pollution problems. We discuss below more stringent requirements both for developing baseline emission rates and for projecting future emission levels.

When we review CAIR SIPs for approvability, we intend to closely review the emissions inventory projections for non-EGUs to evaluate whether the emissions reductions estimates are correct. We intend to review the accuracy of baseline historical emissions for the subject sources, assumptions regarding activity and emissions growth between the baseline year and 2010 and 2015, and assumptions about the effectiveness of control measures.

To quantify non-EGU reductions, as the first step, a historical baseline must be established for emissions of SO
2
and/or NO
X
from the non-EGU source(s) in

a recent year. The historical baseline inventory should represent actual emissions from the substitute sources prior to the application of the emissions controls. We expect that States will choose a representative year (or average of several years) falling between 2002 and 2005, inclusively, for this purpose.

The proposed requirements that follow for estimating the historical baseline inventory reflect EPA's belief that, when States assign emissions reductions to non-EGU sources, those reductions should have a high degree of certainty of actually being achieved similar to EGU reductions which can be quantified with a high degree of certainty in accordance with part 75 monitoring requirements that apply to EGUs. For non-EGU sources which are subject to part 75 monitoring requirements, historical baselines must be derived from actual emissions obtained from part 75 monitored data.

For non-EGU sources that do not have part 75 monitoring data to use as a baseline, a historical baseline must be established that estimates actual emissions in a way that matches or approaches as closely as possible the certainty provided by the part 75 measured data for EGUs. In the absence of part 75 measured data, EPA proposes that States be required to estimate historical baseline emissions using assumptions that ensure a source's or source category's actual emissions are not overestimated; source-specific or category-specific data are required. Because the substitute emissions reductions are estimated by subtracting controlled emissions from a projected baseline, if the historical baseline overestimates actual emissions, the estimated reductions could be higher than the actual reductions achieved. As explained above, the use of historical baselines that do not overestimate emissions helps to ensure that upwind emissions reductions are actually achieved.

To achieve this baseline, States must use emission factors that ensure that emissions are not overestimated (
e.g.,
emission factors at the low end of a range when EPA guidance presents a range) or the State must provide additional information that shows with reasonable confidence that another value is more appropriate for estimating actual emissions. Other monitoring or stack testing data can be considered but care must be taken not to overestimate baselines. If a production or utilization factor is part of the historical baseline emissions calculation, again, a factor that ensures that emissions are not overestimated must be used, or additional data must be provided. Similarly, if a control-efficiency factor and/or rule-effectiveness factor enters into the estimate of historical baseline emissions, it must be realistic and supported by facts or analysis. For these factors, a high value (closer to 100 percent control and effectiveness) ensures that emissions are not overestimated.

Once the historical baseline is established for SO
2
and/or NO
X
emissions from the substitute sources, the second step is to project these emissions to conditions expected in 2010 and 2015. This step results in the 2010 and 2015 baseline emissions estimates. This step must be done with state-of-the-art methods for projecting the source's or source category's economic output. Economic and population forecasts must be as specific as possible to the applicable industry, State, and county of the source, and must be consistent with both national projections and relevant official planning assumptions including estimates of population and vehicle miles traveled developed through consultation between State and local transportation and air quality agencies. However, if these official planning assumptions are themselves inconsistent with official U.S. Census projections of population and energy consumption projections contained in the Annual Energy Outlook published by the U.S. Department of Energy, adjustments must be made to correct the inconsistency, or the SIP must demonstrate how the official planning assumptions are more accurate. Where changes in production method, materials, fuels, or efficiency are expected to occur between the baseline year and 2010 or 2015, these must be accounted for in the projected 2010 and 2015 baseline emissions. The projection must also account for any adopted regulations that will affect source emissions, not including the measures adopted for purposes of meeting the requirements of the proposed CAIR and eligible for that purpose. (See discussion above regarding eligibility of reductions from non-EGU sources.)

The EPA is also proposing an alternative methodology for the use of projected 2010 and 2015 emissions. In this alternative, instead of using the projected 2010 and 2015 emissions as the 2010 and 2015 baselines, States must use the lower of historical baseline emissions for a source category or projected 2010 or 2015 emissions, as applicable, for a source category. This is because, as explained above, changes in production method, materials, fuels, or efficiency often play a key role in changes in emissions. Because of factors such as these, emissions can often stay the same or even decrease as productivity within a sector increases. These factors that contribute to emission decreases can be very difficult to quantify. Underestimating the impact of these types of factors can easily result in a projection for increased emissions within a sector, when a correct estimate would result in a projection for decreased emissions within the sector.

The third step is to develop the 2010 and 2015 controlled emissions estimates by assuming the same changes in economic output and other factors listed above but adding the effects of the new regulations adopted for the purpose of meeting the CAIR. The regulations may take the form of emissions caps, emission rate limits, technology requirements, work practice requirements, etc. The State's estimate of the effect of the regulations must be realistic in light of the specific provisions for monitoring, reporting, and enforcement and experience with similar regulatory approaches. The State's analysis must examine the possibility that these new regulations may cause production and emissions to shift to non-regulated or less stringently regulated sources in the same State or another State. If all sources of an industrial or other type (where any aspect of production is reasonably interchangeable) within the State are regulated with the same stringency and compliance assurance provisions, the analysis of production and emissions shifts need only consider the possibility of shifts to other States. In estimating controlled emissions in 2010 and 2015, assumptions regarding ineligible control measures must be the same as in the 2010 baseline estimates. For example, if a federally adopted and implemented measure for the source type is assumed in one estimate, it must be assumed in the other.

Thus, EPA proposes two alternative methodologies for calculating the 2010 and 2015 emissions reductions from non-EGUs which can be counted toward satisfying the CAIR. In the first alternative, the 2010 and 2015 emissions reductions which can be counted toward satisfying the CAIR are the differences between (i) for 2010, the 2010 baseline emissions estimates and the 2010 controlled emissions estimates, and (ii) for 2015, the 2015 baseline emissions estimates and the 2015 controlled emissions estimates, minus in each case any emissions that may shift to other sources rather than be eliminated.

In the second alternative, the 2010 and 2015 emissions reductions which can be counted toward satisfying the

CAIR are the differences between (i) for 2010, the lower of historical baseline or 2010 baseline emissions estimates and the 2010 controlled emissions estimates, and (ii) for 2015, the lower of historical baseline or 2015 baseline emissions estimates and the 2015 controlled emissions estimates, minus in each case any emissions that may shift to other sources rather than be eliminated.

v. Controls on non-EGUs only. In the January 2004 proposal, we stated that we believe it is unlikely States will choose to control only non-EGUs, but we also said we would propose in this SNPR provisions for determining the specified emissions reductions that must be obtained if States pursue this alternative. In this SNPR, EPA proposes that States choosing this path must ensure the amount of non-EGU reductions is greater than or equivalent to all of the emissions reductions that would have been required from EGUs had the State chosen to assign all the emissions reductions to EGUs, for example by participating in EPA-administered trading programs. For SO
2
emissions, this amount in 2010 would be 50 percent of a State's title IV SO
2
allocations for all affected sources in the State and, for 2015, 65 percent of that amount. For NO
X
emissions, this amount would be the difference between a State's EGU budget for NO
X
under the CAIR and its NO
X
baseline EGU emissions inventory as projected in the Integrated Planning Model (IPM) for 2010 and 2015, respectively. The proposed rule text provides tables of these amounts for both SO
2
and NO
X
.

In addition, EPA proposes that the same requirements described above (in section III.A.4.c of this preamble) regarding the eligibility of non-EGU reductions, emissions control and monitoring, emissions inventories and demonstrations of reductions, will apply to the situation where a State chooses to control only non-EGUs.

B. What Changes Are EPA Proposing for Emissions Reporting Requirements?

1. Purpose and Authority

The EPA believes that it is essential that achievement of the emissions reductions required by the proposed CAIR be verified on a regular basis. Emissions reporting is the principal mechanism to verify these reductions and to assure the downwind affected States and EPA that the ozone and PM2.5 transport problems are being mitigated as required by the proposed CAIR. Also, EPA intends to reassess from time to time whether the requirements of the CAIR are effective in achieving the protections intended by CAA section 110(a)(2)(D)(i) for downwind PM2.5 and ozone nonattainment areas. To this end, EPA is proposing certain, limited new emissions reporting requirements for States. Proposed rule language for these requirements appears at the end of this SNPR. The rule language also would remove or simplify some current emissions reporting requirements which we believe are not necessary or appropriate, for reasons explained below.

Because we are proposing to consolidate and harmonize the new emissions reporting requirements proposed today with two pre-existing sets of emissions reporting requirements, we review here the purpose and authority for emissions reporting requirements in general.

Emissions inventories are critical for the efforts of State, local, and Federal agencies to attain and maintain the NAAQS that EPA has established for criteria pollutants such as ozone, particulate matter (PM), and carbon monoxide (CO). Pursuant to its authority under sections 110 and 172 of the CAA, EPA has long required SIPs to provide for the submission by States to EPA of emissions inventories containing information regarding the emissions of criteria pollutants and their precursors (
e.g.,
volatile organic compounds (VOC)). The EPA codified these requirements in subpart Q of 40 CFR part 51, in 1979 and amended them in 1987.

The 1990 Amendments to the CAA revised many of the provisions of the CAA related to the attainment of the NAAQS and the protection of visibility in Class I areas. These revisions established new periodic emissions inventory requirements applicable to certain areas that were designated nonattainment for certain pollutants. For example, section 182(a)(3)(A) required States to submit an emissions inventory every 3 years for ozone nonattainment areas beginning in 1993. Similarly, section 187(a)(5) required States to submit an inventory every 3 years for CO nonattainment areas. The EPA, however, did not immediately codify these statutory requirements in the CFR, but simply relied on the statutory language to implement them.

In 1998, EPA promulgated the NO
X
SIP Call which requires the affected States and the District of Columbia to submit SIP revisions providing for NO
X
reductions to reduce their adverse impact on downwind ozone nonattainment areas. (63 FR 57356, October 27, 1998). As part of that rule, codified in 40 CFR 51.122, EPA established emissions reporting requirements to be included in the SIP revisions required under that action.

Another set of emissions reporting requirements, termed the Consolidated Emissions Reporting Rule (CERR), was promulgated by EPA in 2002, and is codified at 40 CFR part 51 subpart A. (67 FR 39602, June 10, 2002). These requirements replaced the requirements previously contained in subpart Q, expanding their geographic and pollutant coverages while simplifying them in other ways.

The principal statutory authority for the emissions inventory reporting requirements outlined in this SNPR is found in CAA section 110(a)(2)(F), which provides that SIPs must require “as may be prescribed by the Administrator * * * (ii) periodic reports on the nature and amounts of emissions and emissions-related data from such sources.” Section 301(a) of the CAA provides authority for EPA to promulgate regulations under this provision.
6

6
Other CAA provisions relevant to this SNPR include section 172(c)(3) (provides that SIPs for nonattainment areas must include comprehensive, current inventory of actual emissions, including periodic revisions); section 182(a)(3)(A) (emissions inventories from ozone nonattainment areas); and section 187(a)(5) (emissions inventories from CO nonattainment areas).

2. Existing Emission Reporting Requirements

As noted above, at present, two sections of title 40 of the CFR contain emissions reporting requirements applicable to States: Subpart A of part 51 (the CERR) and section 51.122 in subpart G of part 51 (the NO
X
SIP Call reporting requirements). This SNPR would consolidate these, with modifications as proposed below. The modifications are intended to achieve the additional reporting needed to verify the reductions required by the proposed CAIR, to harmonize the emissions reporting requirements, to reduce and simplify them, and to make them more easily understood.

Under the NO
X
SIP Call requirements in section 51.122, emissions of NO
X
for a defined 5-month ozone season (May 1 through September 30) from sources that the State has subjected to emissions control to comply with the requirements of the NO
X
SIP Call are required to be reported by the affected States to EPA every year. However, emissions of sources reporting directly to EPA as part of the NO
X
trading program are not required to be reported by the State to EPA every year. The affected States are also required to report ozone season emissions and typical summer daily emissions of NO
X
from all sources every

third year (2002, 2005, etc.) and in 2007. This triennial reporting process does not have an exemption for sources participating in the emissions trading programs. Section 51.122 also requires that a number of data elements be reported in addition to ozone season NO
X
emissions. These data elements describe certain of the source's physical and operational parameters.

Emissions reporting under the NO
X
SIP Call as first promulgated was required starting for the emissions reporting year 2002, the year prior to the start of the required emissions reductions. The reports are due to EPA on December 31 of the calendar year following the inventory year. For example, emissions from all sources and types in the 2002 ozone season were required to be reported on December 31, 2003. However, because the Court which heard challenges to the NO
X
SIP Call delayed the implementation by 1 year to 2004, no State was required to start reporting until the 2003 inventory year. In addition, EPA recently promulgated a rule to subject Georgia and Missouri to the NO
X
SIP Call with an implementation date of 2007. (See 69 FR 21604, April 21, 2004.) For them, emissions reporting begins with 2006. These emissions reporting requirements under the NO
X
SIP Call affect the District of Columbia and 22 of the 29 States affected by the proposed CAIR.

As noted above, the other set of emissions reporting requirements is codified at subpart A of part 51. Although entitled the CERR, this rule left in place the separate § 51.122 for the NO
X
SIP Call reporting. The CERR requirements were aimed at obtaining emissions information to support a broader set of purposes under the CAA than were the reporting requirements under the NO
X
SIP Call. The CERR requirements apply to all States.

Like the requirements under the NO
X
SIP Call, the CERR requires reporting of all sources at 3-year intervals (2002, 2005, etc.). It requires reporting of certain large sources every year. However, the required reporting date under the CERR is 5 months later than under the NO
X
SIP Call reporting requirements. Also, emissions must be reported for the whole year, for a typical day in winter, and a typical day in summer, but not for the 5-month ozone season as is required by the NO
X
SIP Call. Finally, the CERR and the NO
X
SIP Call differ in what non-emissions data elements must be reported.

3. Proposed Emissions Reporting Requirements

The EPA proposes to further consolidate the detailed requirements for emissions reporting by States entirely into subpart A, while adding limited new requirements for emissions reports to serve the additional purposes of verifying the CAIR-required emissions reductions. This will allow EPA to monitor compliance with the CAIR, as well as assess from time to time progress in mitigating the interstate transport of ozone and PM
2.5
precursors.

This SNPR would also harmonize the reporting requirements, and reduce and simplify them in several ways. The major changes included in the proposed rule text are described below. A technical support document in the docket provides a detailed explanation of every change and its purpose.
7

7
“Technical Support Document on Emissions Inventory Reporting Requirements for the Proposed Clean Air Interstate Rule (May 2004)” can be obtained from the docket for today's proposed rule: OAR-2003-0053.

Amendments are proposed to subpart A, which contains § 51.1 through 51.45 and an appendix, and to § 51.122 in particular. We also propose to add a new § 51.125.

• In § 51.122, we propose to abolish certain requirements entirely, and to replace certain requirements with a cross reference to subpart A so that detailed lists of required data elements appear only in subpart A. As amended, § 51.122 will specify what pollutants, sources, and time periods the States subject to the NO
X
SIP Call must report and when, but will no longer list the detailed data elements required for those reports.

• The new § 51.125 will be functionally parallel to § 51.122, specifying what pollutants, sources, and time periods the States subject to the proposed CAIR must report and when, referencing subpart A for the detailed data elements required.

• The amended subpart A will list the detailed data elements as well as provide information on submittal procedures, definitions, and other generally applicable provisions.

Taken together, the existing emissions reporting requirements under the NO
X
SIP Call and CERR are already rather comprehensive in terms of the States covered and the information required. Therefore, the practical impact of the changes proposed today is to impose only three new requirements.

First, in Arkansas, Iowa, Louisiana, Mississippi, and Wisconsin, for which we have proposed a finding of significant contribution to ozone nonattainment in another State but which were not among the 22 States subject to the NO
X
SIP Call, the required emissions reporting will be expanded to match those of the 22 States. The change requires that they report NO
X
emissions during the 5-month ozone season, in addition to the existing requirement for reporting emissions for the full year. We are proposing that this new requirement begin with the triennial inventory year prior to the CAIR implementation date. This will be the 2008 inventory year, the report for which will be due to EPA by June 1, 2010.

Second, under the existing CERR, yearly reporting is required only for sources whose emissions exceed specified amounts. Under this SNPR, the 28 States and the District of Columbia subject to the CAIR for reasons of PM
2.5
must report to EPA each year a set of specified data elements for all sources subject to new controls adopted specifically to meet the CAIR requirements related to PM
2.5
, unless the sources participate in an EPA-administered emissions trading program. This is like the every-year reporting requirement for controlled sources under the NO
X
SIP Call, but covering SO2 in addition to NO
X
and covering the whole year—since the PM
2.5
NAAQS at issue is the annual NAAQS—rather than only the ozone season. This proposal could increase the number of sources for which States must submit reports each year rather than only every third year, if a State chooses to control non-EGU sources under this SNPR or if the State does not join the EPA trading programs for EGUs. We are proposing that this new requirement begin with the 2009 inventory year, the report for which will be due to EPA by June 1, 2011. After the 2009 reporting year, this new requirement will have no effect on States that fully comply with the CAIR by requiring their EGUs to participate in the EPA model cap-and-trade programs.

Third, in all States, we are proposing to expand the definition of what sources must report in point source format, so that fewer sources would be included in non-point source emissions.
8

We are proposing to base the requirement for point source format reporting on whether the source is a major source under 40 CFR part 70 for the pollutants

for which reporting is required,
i.e.
, for CO, VOC, NO
X
, SO
2
, PM
2.5
, PM
10
and ammonia but without regard to emissions of hazardous air pollutants. Currently, the requirement for point source reporting is based on actual emissions in the year of the inventory report. This change may require more sources than at present to be reported as point sources every third year. The new approach will make it possible to better track source emissions changes, shutdowns, and start ups over time. It will result in a more stable universe of reporting point sources, which in turn will facilitate elimination of overlaps and gaps in estimating point source, as compared to non-point source, emissions. Under this proposal, States will know well in advance of the start of the inventory year which sources will need to be reported. We are proposing that these new requirements begin with the 2008 inventory year, the report for which will be due to EPA by June 1, 2010. We invite comment on whether this change could instead be practically implemented for the 2005 inventory year, which we believe is desirable if it is practicable. We intend to finalize this proposed change even if for some reason the new emissions reductions requirements of the proposed CAIR and the above two changes in emission reporting requirements are not finalized as proposed, because this change is appropriate for the purposes of monitoring the effectiveness of current SIP programs.

8
We use the term “non-point source” to refer to a stationary source that is treated for inventory purposes as part of an aggregated source category rather than as individual facility. In the existing subpart A of part 51, such emissions sources are referred to as “area sources.” However, the term “area source” is used in section 112 of the CAA to indicate a non-major source of hazardous air pollutants, which could be a point source. As emissions inventory activities increasingly encompass both NAAQS-related pollutants and hazardous air pollutants, the differing uses of “area source” can cause confusion. Accordingly, EPA proposes to substitute the term “non-point source” for the term “area source” in subpart A, § 51.122, and the new § 51.125 to avoid confusion.

A number of proposed changes will reduce reporting requirements on States or provide them with additional options:

• The NO
X
SIP Call rule required the affected States to submit emissions inventory reports for a given ozone season to EPA by December 31 of the following year. The CERR requires similar but not identical reports from all States by the following June 1, 5 months later. The EPA believes that harmonizing these dates would be efficient for both States and EPA. We are proposing to move the December 31 reporting requirement to the following June 1, the more generally applicable submission date affecting all 50 States. We invite comment on whether allowing this 5-month delay is consistent with the air quality goals served by the emissions reporting requirements. However, we also invite comment on the alternative of moving forward to December 31 all or part of the June 1 reporting for all 50 States. In particular, we solicit comment on requiring that point sources be reported on December 31 and other sources on June 1. This approach would eliminate the problem of States having to make two submissions for point sources within a 5-month period, and would result in more timely submission of the emissions information for point sources. More timely submission would be particularly useful for point sources because point sources generally are the primary subject of control measures in SIPs. The later June 1 submission date for non-point sources and mobile sources would allow more time for estimating these emissions sources, which in some cases may require vehicle miles traveled or business activity data not available in time for a December 31 submission. In addition, estimating emissions of some types of non-point sources requires prior knowledge of emissions and activity levels at point sources of the same industrial type; therefore, it makes sense to stagger the submission deadlines for those different sources.

• We also propose to eliminate a requirement of the NO
X
SIP Call for a special all-sources report by affected States for the year 2007, due December 31, 2008. The normal cycle of every-third-year reporting would also produce the same type of all-sources reports for 2005 and 2008. The EPA originally intended to use the information on 2007 emissions to re-assess the effectiveness of the NO
X
SIP Call in eliminating upwind NO
X
emissions that contribute significantly to downwind ozone nonattainment as of the latest 1-hour ozone attainment date within the region. The large majority of the emissions reductions required by the NO
X
SIP Call have been assigned to sources that participate in the EPA-administered trading program, which has independent procedures to ensure that emissions reductions are achieved. We now believe that examining 2005 and 2008 inventory submissions and the annual reporting on controlled sources will permit us to evaluate the effectiveness of individual State rules or implementation practices in reducing emissions. We no longer need the special 2007 emissions inventory information to broadly revisit the NO
X
SIP Call, and we recognize that preparing that inventory could draw resources away from more important work by State air agencies.

• We propose to remove a requirement in the existing CERR for reporting annual and typical ozone season day biogenic emissions. Because biogenic emissions vary greatly with daily weather conditions and because there are other practical methods for obtaining hourly estimates across whole regions when needed by EPA, States, or others, we believe this requirement for reporting biogenic emissions serves no useful purpose. This change does not affect our expectation that biogenic emissions be appropriately considered in ozone and PM
2.5
attainment demonstrations.

• We are proposing a new provision which would allow States the option of providing emissions inventory estimation model inputs in lieu of actual emissions estimates, for source categories for which prior to the submission deadline EPA develops or adopts suitable emissions inventory estimation models and by guidance defines their necessary inputs. This provision will allow source reporting to evolve to take advantage of new emissions estimation tools for greater efficiency, although the States will remain required to provide inputs representative of their conditions. We propose this option be available starting with the reports on 2003 emissions.

• We are proposing to delete the existing requirement that all States report emissions for a winter work weekday. This requirement was originally aimed at tracking progress towards attainment of the CO NAAQS. We believe applying this requirement to all States is no longer warranted given that CO violations are currently observed in few areas. We believe we can work directly with the remaining affected States to monitor efforts to attain, without requiring formal submission of CO inventories.

The NO
X
SIP Call rule and the CERR contain detailed lists of required data elements in addition to emissions, and each rule has its own set of definitions. The two sets of data elements overlap but are not identical. Generally, the NO
X
SIP Call rule required more data elements to be reported. The EPA has reviewed both lists in light of more recent experiences and insight into the difficulty States face in collecting and submitting these data elements and their utility to EPA, other States, and other users. We are proposing to combine the separate lists of required elements into a single new list of required data elements. A few data elements are proposed to be eliminated, as explained in the technical support document for inventory reporting. We propose that these relatively minor changes become applicable starting with the first required emissions reports following the promulgation of the final CAIR, which we expect to be the reports regarding emissions during 2003, due June 1, 2005.

There are a number of currently required data elements that have been kept in the proposed rule text, but on which we invite comment as to whether

they should be dropped in the final rule. These are heat content (fuel), ash content (fuel), sulfur content (fuel) for fuels other than coal, activity/throughput, hours per day in operation, days per week in operation, weeks per year in operation, and start time in the day. These data elements have been carried forward from emissions reporting systems dating back many years. We believe it is appropriate to take comment on their current usefulness.

We also invite comment on whether the current data elements that describe emissions control equipment type and efficiency are adequate. We believe it is important for States to report on the manner in which sources are currently controlled so that opportunities for additional highly cost-effective controls can be assessed from time to time, but the existing data elements may not be adequate and appropriate for that purpose. The present data elements related to control measures are primary control efficiency, secondary control efficiency, control device type, and rule effectiveness for point sources; and total capture/control efficiency, rule effectiveness, and rule penetration for non-point sources and nonroad mobile sources.
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9
Additional information on emissions data elements and the formats and valid codes presently in use for State reporting to EPA is available on the EPA Web site
http://www.epa.gov/ttn/chief/nif/index.html.

We are proposing to retain the requirement for reporting of summer day emissions from all sources (except biogenic sources) at 3-year intervals, but to restrict it to only States with ozone nonattainment areas or for which we are proposing a finding of significant contribution to ozone nonattainment in another State. The NO
X
SIP Call requires reporting only of NO
X
emissions for a typical summer day, while the CERR requires reporting of all pollutants. We propose to restrict the requirement to VOC and NO
X
emissions, but we invite comment on whether CO emissions should be required also.

At present, States are required to report three particular data elements for point source stacks: Stack diameter, exit gas velocity, and exit gas flow rate. This is a redundant requirement, since any one of these can be calculated from the other two. We invite comment on which of these to drop from the required list of data elements, if any. Our preference would be to collect the data element that is most closely tied to an actual operating measurement. Alternatively, we may allow States to report either exit gas flow or exit gas velocity, at their option.

Finally, we propose to modify section 51.35 of subpart A, to provide that if States obtain one-third of their necessary emissions estimates from point sources and/or prepare one-third of their non-point or mobile source emissions estimates each year on a rolling basis, they should submit their data as a single package on the required every-third-year submission date.

C. Acid Rain Program

In this SNPR, EPA proposes several revisions of the Acid Rain Program regulations (40 CFR parts 72 through 78). Most of the proposed revisions would affect the provisions in the regulations concerning the requirement to hold allowances sufficient to authorize annual SO
2
emissions. These proposed revisions would facilitate the interaction of the Acid Rain Program with the proposed CAIR trading program. However, because these proposed modifications also would benefit the implementation of the existing Acid Rain Program, EPA is proposing to adopt them regardless of whether other rules proposed in the CAIR are adopted.

As the basis for these proposed revisions of the Acid Rain Program regulations, EPA proposes to modify its interpretation of title IV of the CAA and, specifically, provisions in sections 403, 404, 405, 408, 409, 411, and 414, concerning the requirement to hold allowances. Provisions in each of these sections address the allowance-holding requirement by: Stating the requirement that sufficient allowances be held for a unit after a calendar year to authorize emissions at least equal to the unit's tonnage of SO
2
emissions during that year; referencing this requirement; or establishing the penalties and offsets for violation of this requirement.

The following is a description of these statutory provisions. Section 403(g) is a general prohibition barring each affected unit from emitting SO
2
in excess of the number of allowances “held for that unit for that year by the owner or operator of the unit” (42 U.S.C. 7651b(g)). Various provisions in sections 404 and 405 refer to existing units (those commencing commercial operation before November 15, 1990) and state that a unit's emissions may not exceed its allowance allocation unless the owner or operator of such unit “holds allowances to emit not less than the unit's total annual emissions” (42 U.S.C. 7651c(a), 7651c(c)(2), 7651c(d)(1) and (5), 7651d(b)(1) and (3), 7651d(c)(1) through (3) and (5), 7651d(d)(1) and (2), 7651d(e), 7651d(f)(1), 7651d(h)(1)).
10

Section 403(e) refers to new units and States that it is unlawful for such a unit “to emit an annual tonnage of sulfur dioxide in excess of the number of allowances to emit held for the unit by the unit's owner or operator” (42 U.S.C. 7651b(e)).
11

Section 403(d)(1) provides that “the total tonnage of emissions in any calendar year (calculated at the end thereof) from all units in such a utility system, power pool, or allowance pool agreements shall not exceed the total allowances for such units for the calendar year concerned” (42 U.S.C. 7651b(d)(2)). Section 403(f) states that each permit under titles IV and V of the CAA must provide that “the affected unit may not emit an annual tonnage of sulfur dioxide in excess of the allowances held for that unit” (42 U.S.C. 7651b(f)).
12

Section 411(a) establishes the owner or operator's liability for an excess emissions penalty if SO
2
is emitted at the unit in excess of the “allowances the owner or operator holds for use for the unit for that calendar year” (42 U.S.C. 7651j(a)).
13

Finally, section 414 provides that the operation of an affected unit to emit SO
2
in excess of “allowances held for such unit” is a violation of the CAA, with each ton emitted in excess of allowances held constituting a separate violation (42 U.S.C. 7651m).

10

See also
42 U.S.C. 7651h(f) (section 409(f), referring to repowered sources and the “prohibition against emitting sulfur dioxide in excess of allowances held”).

11

See also
42 U.S.C. 7651d(g)(1) (section 405(g)(1), referring to certain new units and stating that a unit's emissions may not exceed its allowance allocation unless the owner or operator of such unit “holds allowances to emit not less than the unit's total annual emissions”).

12

See also
42 U.S.C. 7651g(a) (section 408(a)(1), stating that each permit must prohibit “annual emissions of sulfur dioxide in excess of the number of allowance to emit sulfur dioxide the owner or operator, or the designated representative of the owners or operators, of the unit hold for the unit”); and 42 U.S.C. 7651g(d)(4) (section 408(d)(4), stating that each Phase II permit must bar “affected units at the affected source” from emitting “in excess of the number of allowances to emit sulfur dioxide the owner or operator or designated representative hold for the unit”).

13

See also
42 U.S.C. 7651j(b) (section 411(b), stating that the owner or operator of “any affected source that emits sulfur dioxide during any calendar year in excess of * * * the allowances held for the unit for the calendar year” is liable for an equal tonnage offset of the excess emissions).

In summary, sections 403(e) through (g), 408(a) and (d), 411(a) and (b), and 414 all state that the owner or operator must hold allowances “for the unit” at least equal to the unit's SO
2
emissions. While section 403(d)(2) refers to “all units” on a “utility system's power pool, or allowance pool agreements,” EPA interprets this provision as consistent with the requirement that

allowances must be held for each such unit at least equaling the unit's emissions.
14

The remaining provisions cited above contain a more shorthand reference to the allowance-holding requirement by simply stating that the owner or operator must hold sufficient allowances for a unit's emissions.

14

See
64 FR 25835-25837 (explaining that the legislative history of section 403(d)(2) indicates that the provision was not intended to require or authorize aggregation of such units' allowances to determine compliance with the allowance-holding requirement).

Moreover, section 403(b) of the CAA requires the Administrator to establish by regulation the allowance tracking system, including the requirements for “allocation, transfer, and use of allowances” (
e.g.,
for the holding of allowances). 42 U.S.C. 7651b(b). For example, in establishing the allowance tracking system, the regulations must specify which accounts in the allowance tracking system must contain allowances used to meet the allowance-holding requirement. However, none of the above-described statutory provisions on the allowance-holding requirement specifically identify the type of account in which a unit's owner or operator must hold allowances in order to meet that requirement. In particular, these statutory provisions do not state, and thus are ambiguous concerning, whether the account must be an account unique to the unit “for” which allowances are held (
i.e.,
a unit-level account) or whether the account can be “for” all units at a given source (
i.e.,
a source-level account).

The EPA has exercised its authority under section 403(b) in several prior rulemakings, in which EPA considered the question of what type of account could be used to hold allowances “for” a unit to meet the allowance-holding requirement. In the initial rulemaking for the Acid Rain Program that resulted in the January 11, 1993 core rules for the program, EPA interpreted the statutory provisions on allowance holding to mean that, in general, allowances “for” a unit could be held only in an account unique to that unit (referred to in the regulations as a “unit account”). (
See
63 FR 41358, 41362, August 3, 1998) (discussing that allowances had to be held in a subaccount (the “compliance subaccount”) of the unit account). Even so, the January 11, 1993 rules include an exception, continued in the existing rules, for affected units that share a common stack and monitor at the stack, not at the individual units. For such common-stack units, the designated representative has the option to assign (before the allowance transfer deadline) a percentage of allowances to be deducted from the unit account for each unit so that the total deduction for all the common-stack units equals the total annual emissions from these units. If the option is not exercised, an equal percentage of the allowances is deducted from the unit account of each unit. The assigned, or the default, deductions need not have any relationship to the actual distribution of emissions among the common-stack units. Consequently, the treatment of common-stack units effectively allows the allowances in a unit's unit account to be used to cover emissions from another unit at the same source. (
See
63 FR 41362.)

In a rulemaking completed in May 1999, EPA reconsidered and revised its interpretation of title IV, and revised the Acid Rain Program regulations, in order to allow a unit to use some allowances in the unit account of another unit at the source to meet the allowance-holding requirement. (64 FR 25834, May 13, 1999). This revision applied to units at the same source even if they were not common-stack units. The revised regulations resulting from that rulemaking allow a unit to use allowances in the unit account of another unit at the same source up to a limit equal to the greater of: 95 percent of the difference between the first unit's emissions and the allowances in its own unit account; or 10 tons. See 40 CFR 73.35(b)(3) (§ 73.35(b)(3)). This approach effectively allows the owner or operator to approach source-wide compliance in that, except for the above-described limit, allowances at one unit are considered to be held “for” another unit at the same source and can be used to meet the allowance-holding requirement. The EPA explained that the limit on using another unit's allowances would “provide owners and operators with a strong incentive to hold sufficient allowances in an affected unit's account” and that compliance would “routinely” be achieved on a unit-by-unit basis. (64 FR 25837). In adopting this interpretation of the ambiguous language in title IV concerning the allowance-holding requirement, EPA stated that it was balancing the general unit-by-unit orientation of title IV and the need for “compliance flexibility.” Compliance flexibility is necessary to reduce excess emission penalties where there are insufficient allowances in the unit's unit account due to “inadvertent, minor errors” but enough allowances in the account of another unit at the same source.

In today's SNPR, EPA is reconsidering the extent to which allowances in the account of one unit at a source can be used to meet the allowance-holding requirement for another unit at the same source. There are several factors relevant to this reconsideration. The first factor is that, as discussed above, the statutory provisions setting forth the allowance-holding requirement do not specifically refer to allowance accounts, much less dictate the type of account in which allowances must be held “for the unit” in meeting this requirement. To the extent only allowances held in a unit-level account are treated as being held “for” the unit involved, compliance must be met on an individual-unit basis. To the extent all allowances held in a source-level account are treated as being held “for” all units at the source involved, compliance may be met on a source-wide basis. In light of the ambiguity in the statutory allowance-holding-requirement provisions, EPA believes that it has discretion in determining whether to apply the allowance-holding requirement at the unit level or the source level. Indeed, EPA maintains that the degree of compliance flexibility that was provided in the May 13, 1999 rulemaking did not exhaust EPA's discretion in moving toward source-level compliance.

The second factor considered by EPA is that it is important to provide compliance flexibility by allowing one unit at a source to use, for compliance, allowances from other units at that source. The statutory excess emissions penalty of $2,000 (adjusted for inflation since 1990 to about $2,900) per ton is over ten times the current market value of an allowance. Moreover, unlike the general civil penalties under section 113 for violations of the CAA, section 411 makes the excess emission penalty automatic (not discretionary) and therefore applicable to all excess emissions at a unit, even if they result from inadvertent, minor errors by the owner or operator. Consequently, companies have potential liability for large excess emissions penalty payments for what may be inadvertent, minor errors. For example, a company may have acquired enough allowances to authorize all the annual emissions from units at a source but incorrectly distributed the allowances among the unit accounts for those units. The distribution may be incorrect because of something as simple as: An error by the owner or operator in calculating how many allowances will remain in each unit account after allowance transfers submitted just before the allowance transfer deadline are recorded; an error in the allowance amount, or in the account number of the transferee, listed

in an allowance transfer form; or an error in identifying the unit for which collected emission data are reported.

In the May 13, 1999 rulemaking, EPA partially addressed this problem by allowing a unit with fewer allowances in its unit account than emissions to use allowances in the unit accounts of other units at the source, but with a limit on that use. (
See
63 FR 41360 and 64 FR 25838-25839). Under the current § 73.35(b)(3), the unit may use allowances from other units at the source to eliminate up to the greater of: 95 percent of that unit's allowance deficit; or 10 tons. While this can significantly reduce a unit's potential liability for excess emission penalty payments, the excess emission penalty payments can still be quite large, particularly when the allowance deficit is large enough that the 95 percent limit, rather then the 10-ton limit, applies. The 95 percent limit applies whenever the allowance deficit exceeds 200. An error, such as reversing digits in the allowance amount in a transfer form or misidentifying the unit for which collected emission data are reported, can easily result in a very large allowance deficit and therefore in a large penalty payment when the 95 percent limit on use of other units' allowances applies. In short, the current provisions in § 73.35(b)(3) do not fully (and in EPA's view do not sufficiently) address the problem of excess emission penalty payments that potentially are far out of proportion to the errors involved.

The third factor considered by EPA is that, as noted in prior rulemakings, title IV evidences in language addressing matters beyond the allowance-holding requirement a “pervasive unit-by-unit orientation.” (See 63 FR 41360). For example, the applicability of title IV is determined on a unit-by-unit basis under sections 402 (definitions of “unit,” “existing unit,” “new unit,” “utility unit,” and “affected unit”), 403(e), 404(a)(1), and 405. Allowances are allocated, and annual SO
2
emission limitations are set, for individual units. Under section 411(a), excess emissions penalties are imposed on owners and operators of units that have excess emissions, while, under section 411(b), offsets of excess emissions are imposed on owners and operators of sources with units that have excess emissions. Section 412(a) requires unit-by-unit monitoring of emissions, except that, in the case of units at a common stack, separate monitors for each unit are not required if sufficient information for compliance determinations is provided.

Balancing the three above-described factors, EPA proposes to revise the Acid Rain regulations to allow a unit to use for compliance any allowances from other units at the same source.
15

This approach limits the extent of deviation from the unit-by-unit orientation evidenced in the non-allowance-holding provisions of title IV in that a unit may only use allowances held for other units that are at essentially the same geographic location as that unit,
i.e.
, other units that are at the same source. Moreover, there are no significant environmental consequences to shifting from unit- to source-level compliance. This approach is also feasible in that it does not require any dramatic changes in the operation of the Acid Rain Program. For example, only one designated representative (
i.e.
, the designated representative of the source at which the units are located) will be involved in ensuring that there are sufficient allowances to cover emissions as of the allowance transfer deadline. It also appears that this approach will result in a minimum of changes to existing contracts involving allowance agreements among different owners of units at a source. This is because § 73.35(b)(2) already allows a unit to use allowances from other units at the same source within certain limits (
i.e.
, the 95 percent and 10 ton limits described above), and today's SNPR simply removes those limits.

15
For the reasons set forth in the preamble of the May 13, 1999 final rule, EPA maintains that allowing company-level compliance or compliance at any other, higher level is neither required by title IV nor appropriate.
See
64 FR 25835-25837.

In order to implement the proposal to allow a unit to use allowances from other units at the same source without limit, EPA is proposing the following specific changes to the Acid Rain Program regulations. The EPA's objective is to implement the proposal, but with a minimum of changes to the language of the Acid Rain Program regulations. Other than implementing the proposed shift from unit- to source-level compliance, these proposed revisions are not intended to make any substantive changes to the revised provisions.

1. The term “unit account” is replaced by “compliance account” in § 72.2 and, as appropriate, in every other provision of the Acid Rain Program regulations in which the term appears. Similarly, references to a “unit's” account in the Allowance Tracking System are replaced by references to a “source's” account. In addition, references to allowances held by a “unit” are changed to refer to allowances held by a “source.”

2. References to a “unit's” Acid Rain emissions limitation for SO
2
are replaced by references to a “source's” Acid Rain emissions limitation for SO
2
throughout the Acid Rain Program regulations. Similarly, references to a “unit's” SO
2
emissions for purposes of applying the SO
2
emissions limitation (or a “unit's” excess emissions) are replaced, where appropriate, by references to the SO
2
emissions of the “affected units at a source” or to a “source's” excess emissions. It should be noted that the proposed rule language accompanying this preamble attempts to list every instance in which the terms “unit's” Acid Rain emissions limitation for SO
2
and “unit's” SO
2
emissions or excess emissions (as well as the terms “unit account,” a “unit's” account, and allowances held by a “unit”) appear and should be replaced. However, even if some instances were missed, EPA proposes to replace the term in all instances necessary to implement source-level compliance with the allowance-holding requirement and requests comment on, among other things, what other instances may have been missed.

3. The provisions in §§ 72.90(b)(5) and 73.35(e) concerning the assignment of allowance deductions among units at a common stack are removed. These provisions are unnecessary with the shift from unit- to source-level compliance.

4. The terms “compliance subaccount,” “future year subaccount,” and “current year subaccount” (and their definitions) are removed or replaced, as appropriate, throughout the Acid Rain Program regulations. The current regulations distinguish between two subaccounts in each unit account,
i.e.
, the “compliance subaccount” for allowances usable for compliance in a given year and a “future year subaccount” for allowances not usable until a future year. Similarly, the current regulations refer to a “current year subaccount” of a general account. The electronic Allowance Tracking System does not currently use or refer to these subaccounts. Moreover there is also no need to use or refer to them when compliance is on a source-level basis. The proposed rule language accompanying this preamble attempts to list every provision in which the terms “compliance subaccount,” “future year subaccount,” and “current year subaccount” appear and to modify the provision as necessary to remove these terms without changing the substance of the provision. However, even if some instances were missed, EPA proposes to replace the terms in all instances and requests comment on, among other things, what other instances may have been missed.

5. The provision in § 73.35(b)(3) limiting the use of allowances from another unit at the same source for compliance is removed.

The EPA notes, in addition to the above-des

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Source: Frix Law Library, https://www.frixlaw.com/law-library/documents/fr%3A04-11923. Public record. Not legal advice.