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Proposed Rule

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

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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 (SO2) and oxides of nitrogen (NOX)—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.

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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.

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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 NOX and SO2. 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. SO2 Emissions Budgets

B. NOX 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. NOX 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 NOX and SO2 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 SO2 and NOX from 28 States and DC, and emissions of NOX 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).

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 NOX and SO2 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 Start Printed Page 32686appropriate 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 SO2 and NOX 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 SO2 and NOX emissions reductions—and the NOX SIP Call, which was a 1998 rulemaking that required States in the eastern U.S. to submit SIPs reducing NOX 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 SO2 and NOX 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]

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 NOX 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 SO2 and NOX 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. SO2 Emissions Budgets

1. Approaches for Integrating SO2 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 SO2 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 SO2 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 SO2 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 Start Printed Page 32687allowances 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 SO2 State Emission Budget Methodology

a. Overview. In this section, EPA discusses the methodology for apportioning regionwide SO2 emissions reductions requirements or budgets to the individual States. In the January 2004 proposal we proposed State EGU SO2 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 SO2 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 SO2 emission budget methodology at length in the January 2004 proposal. In that discussion, EPA outlined the various reasons for tying the SO2 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 SO2, 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]

Table II-1.—28-State and District of Columbia Annual EGU SO2 Budgets

State28-State SO2 Budget 2010 (tons)28-State SO2 Budget 2015 (tons)
Alabama157,582110,307
Arkansas48,70234,091
Delaware22,41115,687
District of Columbia708495
Florida253,450177,415
Georgia213,057149,140
Illinois192,671134,869
Indiana254,599178,219
Iowa64,09544,866
Kansas58,30440,812
Kentucky188,773132,141
Louisiana59,94841,963
Maryland70,69749,488
Massachusetts82,56157,792
Michigan178,605125,024
Minnesota49,98734,991
Mississippi33,76323,634
Missouri137,21496,050
New Jersey32,39222,674
New York135,13994,597
North Carolina137,34296,139
Ohio333,520233,464
Pennsylvania275,990193,193
South Carolina57,27140,089
Tennessee137,21696,051
Texas320,946224,662
Virginia63,47844,435
Start Printed Page 32688
West Virginia215,881151,117
Wisconsin87,26461,085
Total Regional Budget3,863,5662,704,490
 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 SO2 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 SO2 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 SO2 budget of 300,000 tons in 2010, reflecting a 50 percent reduction from its 600,000 2010 title IV SO2 allowances. Assume also that State A decides to implement a 3-to-1 retirement ratio for its 600,000 title IV SO2 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 SO2 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. NOX Emissions Budgets

1. Overview

In this section, EPA discusses the apportioning of proposed regionwide NOX emission reduction requirements or budgets to the individual States. In the January 2004 proposal we proposed State EGU NOX 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 NOX 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 NOX budgets to individual sources.

2. NOX Emission Budget Methodology Proposed in the NPR

a. NPR discussion. In the January 2004 proposal, we proposed annual NOX 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 NOX 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 Start Printed Page 32689from 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 NOX 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 NOX 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 NOX Budgets—Based on Heat Input

StateState NOX Budget 2010 (tons)State NOX Budget 2015 (tons)
Alabama67,42256,185
Arkansas24,91920,765
Delaware5,0894,241
District of Columbia215179
Florida115,50396,253
Georgia63,57552,979
Illinois73,62261,352
Indiana102,29585,246
Iowa30,45825,381
Kansas32,43627,030
Kentucky77,93864,948
Louisiana47,33939,449
Maryland26,60722,173
Massachusetts19,63016,358
Michigan60,21250,177
Minnesota29,30324,420
Mississippi21,93218,277
Missouri56,57147,143
New Jersey9,8958,246
New York52,50343,753
North Carolina55,76346,469
Ohio101,70484,753
Pennsylvania84,55270,460
South Carolina30,89525,746
Tennessee47,73939,783
Texas224,314186,928
Virginia31,08725,906
West Virginia68,23556,863
Wisconsin39,04432,537
Total Regional Budget1,600,7991,333,999

Note:

NOX 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 NOX 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 NOX SIP Call, annual NOX 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 NOX 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 NOX emissions. Finally, this section Start Printed Page 32690provides 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 NOX 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 NOX emissions) and 40 CFR 51.124 (for SO2 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 SO2. Thus, although the Phase I cap does not come into place until 2010, the proposed program would achieve substantial reductions in SO2 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 SO2 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 NOX and SO2 partial year budgets. For the NOX 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 NOX 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 Start Printed Page 32691the simplest pro-rata methodology described above would be appropriate for a partial year allocation.

Budgets for SO2 could be set in a similar way. A State's SO2 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 SO2 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 NOX and SO2 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 (NOX emissions reductions) and in the proposed 40 CFR 51.124 (SO2 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 NOX and SO2 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 NOX 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 SO2 and NOX. 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 NOX and SO2 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 NOX and SO2 emissions trading programs, States must still impose an emissions cap as well as part Start Printed Page 3269275 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 NOX and SO2 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 SO2 allowances for vintage year 2010 and beyond for the State's EGUs that exceed the State's CAIR EGU SO2 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 SO2 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 NOX 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 NOX 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 SO2 budget and/or an EGU NOX 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 SO2 EGU budget in Table VI-9 and a State's selected higher EGU SO2 budget would be the amount of SO2 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 NOX EGU budget in Table VI-10 and a State's selected higher EGU NOX budget would be the amount of NOX emissions reductions the State must demonstrate it will achieve from non-EGU sources.

If States require SO2 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 Start Printed Page 32693of credit is consistent with the NOX 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]

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 SO2 and/or NOX from the non-EGU source(s) in Start Printed Page 32694a 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 SO2 and/or NOX 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 Start Printed Page 32695CAIR 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 SO2 emissions, this amount in 2010 would be 50 percent of a State's title IV SO2 allocations for all affected sources in the State and, for 2015, 65 percent of that amount. For NOX emissions, this amount would be the difference between a State's EGU budget for NOX under the CAIR and its NOX 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 SO2 and NOX.

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 NOX SIP Call which requires the affected States and the District of Columbia to submit SIP revisions providing for NOX 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]

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 NOX 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 NOX SIP Call requirements in section 51.122, emissions of NOX 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 NOX 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 NOX 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 NOX from all sources every Start Printed Page 32696third 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 NOX emissions. These data elements describe certain of the source's physical and operational parameters.

Emissions reporting under the NOX 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 NOX 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 NOX 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 NOX 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 NOX 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 NOX SIP Call. The CERR requirements apply to all States.

Like the requirements under the NOX 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 NOX 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 NOX SIP Call. Finally, the CERR and the NOX 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 PM2.5 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]

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 NOX 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 NOX 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 NOX SIP Call, the required emissions reporting will be expanded to match those of the 22 States. The change requires that they report NOX 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 PM2.5 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 PM2.5, unless the sources participate in an EPA-administered emissions trading program. This is like the every-year reporting requirement for controlled sources under the NOX SIP Call, but covering SO2 in addition to NOX and covering the whole year—since the PM2.5 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 Start Printed Page 32697for which reporting is required, i.e., for CO, VOC, NOX, SO2, PM2.5, PM10 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.

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

  • The NOX 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 NOX 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 NOX SIP Call in eliminating upwind NOX 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 NOX 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 NOX 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 PM2.5 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 NOX 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 NOX 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 Start Printed Page 32698they 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.[9]

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 NOX SIP Call requires reporting only of NOX emissions for a typical summer day, while the CERR requires reporting of all pollutants. We propose to restrict the requirement to VOC and NOX 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 SO2 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 SO2 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 SO2 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 SO2 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 SO2 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).

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 SO2 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 Start Printed Page 32699allowances 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.

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 Start Printed Page 32700in 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 SO2 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.

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 SO2 are replaced by references to a “source's” Acid Rain emissions limitation for SO2 throughout the Acid Rain Program regulations. Similarly, references to a “unit's” SO2 emissions for purposes of applying the SO2 emissions limitation (or a “unit's” excess emissions) are replaced, where appropriate, by references to the SO2 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 SO2 and “unit's” SO2 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. Start Printed Page 32701

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-described rule changes, shifting from unit- to source-level compliance under the Acid Rain Program would require revisions to the software used to operate the Allowance Tracking System and to reconcile allowances and emissions after the end of each calendar year. For example, one approach might be to revise the software to aggregate and convert unit accounts in the Allowance Tracking System to source-level compliance accounts. The system would need to move the allowances in the unit accounts of all affected units at a given source to the new source-level compliance account and ensure recordation in the compliance account of the allowances allocated to such units. In addition, annual emissions for the affected units at a source would have to be summed and then compared with the allowances in that source's compliance account. Because of the time necessary to revise the software and to conduct testing to ensure that the Allowance Tracking System operates properly, EPA believes that the rule changes implementing source-level compliance, if adopted in a final rule, should not become effective before July 1, 2005. Under that approach, compliance under the Acid Rain Program for the 2004 calendar year (which is determined after the allowance transfer deadline for 2004, i.e., March 1 or the next business day if March 1 is not a business day) would remain at the unit-level, and compliance would shift to the source-level for the 2005 calendar year. An effective date of July 1, 2005 would ensure that the source-level rule changes would take effect after completion of the process of determining compliance for 2004. The EPA's experience is that the compliance determination process is generally completed several months after the end of the year for which emissions and allowances are compared. The July 1, 2005 effective date would give owners and operators, as well as EPA, the opportunity to adjust internal procedures to take account of source-level compliance. The EPA requests comment on a July 1, 2005 effective date for the Acid Rain Program rule changes discussed in today's notice and on any alternative effective dates for such rule changes.

The EPA further notes that not only is the proposed shift to source-level compliance consistent with title IV and an improvement to the operation of the Acid Rain Program, but also this change would facilitate the coordination of this program with the proposed CAIR trading program. The latter program, of course, requires source-level compliance.

The EPA is also proposing other revisions of the Acid Rain Program that do not address the allowance-holding requirement but that are focused on facilitating the interaction of the Acid Rain Program and the proposed CAIR trading program. For example, certain language in the definition of “cogeneration unit” in § 72.2, which definition was recently changed (See 67 FR 40420, June 12, 2002), is changed back to the original language so that it is consistent with certain language in the proposed definition of “cogeneration unit” in the CAIR model trading rules. See section IV below.

Further, the language required in § 72.21(b)(1) for the certification that must be in each submission by the designated representative in the Acid Rain Program would be revised so that the same submission-certification language can be used for submissions for units whether the units are in both the CAIR trading program and the Acid Rain Program or in only one of the programs. Similarly, certain language required in § 72.24 (paragraphs (a)(5), (a)(7), and (a)(10)) for the certificate of representation for the designated representative in the Acid Rain Program would be removed so that the same, standard certificate can be used for units that are in one or both programs. This would remove requirements (e.g., for a 1-day newspaper notice of the designation of a designated representative) that EPA believes have proved to be unnecessary. For the same reason, certain language required in § 73.31(c)(v) for the certificate of representation for an authorized account representative in the Acid Rain Program would be removed as unnecessary. With the proposed changes in §§ 72.24 and 73.31, the language for certificates of representation in the Acid Rain Program and the CAIR trading program would be the same as the language in the certificates of representation in the NOX Budget Trading Program under the NOX SIP Call.

A further example is that the general requirement for all affected sources to submit compliance certification reports at the end of each year is removed as superfluous. Sources already are required to submit compliance certification reports under title V of the CAA that cover compliance with CAA requirements, including the Acid Rain Program requirements. Moreover, the quarterly emissions reports that each unit must submit already include a certification of compliance with the monitoring and reporting requirements under part 75 of the Acid Rain Program regulations. The proposed CAIR trading programs do not require submission of annual compliance certification reports.

In addition, several provisions in the Acid Rain Program regulations concerning the allowance tracking system are proposed to be removed or revised in order to make the allowance tracking systems in the Acid Rain Program, the NOX Budget Trading Program, and the proposed CAIR trading program as similar as possible. For example, § 73.32 has proved to be superfluous (and includes obsolete references to compliance and current year subaccounts) and would be removed. Section 73.33(c) imposes a one-day newspaper notice requirement for authorized account representatives that has proved to be unnecessary and would be removed. Sections 73.37(a) through (d) would be removed since the claim of error procedure has proved to be superfluous and has not been used. Similarly, §§ 73.50 and 73.52 would be revised to remove superfluous language and to conform to the provisions under the NOX Budget Trading Program and the proposed CAIR trading program. For instance, language referencing allowance transfers in perpetuity is removed as superfluous since such transfers are allowed under these sections (and in the NOX Budget Trading Program) even without such language.

D. NOX SIP Call

1. Emissions Reduction Requirements

Today's SNPR requires additional reductions in NOX from States affected by the NOX SIP Call. However, this SNPR would not relieve those States from the requirements of the NOX SIP Call. Except as explained below, States should retain all of the SIP provisions that they adopted to meet the requirements of the NOX SIP Call.

All of the States subject to the NOX SIP Call (with the exception of Georgia and Missouri, which are not required to submit SIPs until 2005) chose to meet at least part of their emission reduction requirement by including their EGUs in a multi-State ozone season NOX trading program. The EPA has performed modeling of expected NOX emissions from EGUs assuming that all States affected by the proposed CAIR achieve all of their required NOX reductions under the CAIR by including their EGUs in a regionwide annual NOX cap-and-trade program. Based on that modeling, EPA has proposed that if States achieve all of the mandated NOX reductions by Start Printed Page 32702including their EGUs in the regionwide, annual NOX cap-and-trade program managed by EPA, EPA will consider the reductions from that program to also meet the ozone season reduction requirements that States were previously achieving from EGUs participating in a regionwide ozone season NOX cap-and-trade program. Under these circumstances, EGUs in a State achieving all of the required NOX reductions from only EGUs would not be subject to a seasonal NOX cap-and-trade program unless the State elects to retain such a program. The EPA believes this approach would simplify compliance for sources and avoid the potential administrative burden of implementing both a seasonal and annual cap-and-trade program for EGUs.

2. NOX SIP Call Cap-and-Trade Program for Non-EGUs

The EPA is proposing to continue administering an ozone season only NOX cap-and-trade program for non-EGUs that are subject to the requirements of the regionwide NOX SIP Call cap-and-trade program. In today's SNPR, EPA proposes modifications to part 51 of the NOX SIP Call to reflect the continued participation of non-EGUs in the ozone season NOX cap-and-trade program and the removal of EGUs from their ozone season NOX limitations.

Maintaining the ozone season reductions from non-EGUs in the NOX SIP Call is important for limiting their interstate contribution to ozone nonattainment. The EPA considered whether it would be appropriate to allow States to include non-EGUs in the annual CAIR trading program and relieve them from the requirements of the ozone season NOX trading program. However, EPA does not have sufficient information to project whether non-EGUs would continue to meet their ozone season NOX reduction requirements if they were subject to an annual limitation only. Therefore, EPA is proposing to continue to run the NOX SIP Call cap-and-trade program for non-EGUs.

The EPA acknowledges that, if non-EGUs are only permitted to trade with other non-EGUs, the robustness of the existing NOX SIP Call allowance market must be maintained to provide incentives for non-EGUs to find cost-effective emissions reductions. States that are concerned for the future health of the market may choose to revise their SIPs to achieve the non-EGU NOX emissions reductions using an alternate approach. The EPA solicits comment on the potential effects that removing EGUs from the NOX SIP Call trading market may have on the robustness of the market and any alternative mechanisms for addressing these concerns.

The EPA solicits comment on the above proposal and any other approaches.

3. NOX Early Reduction Credits [16]

Today's SNPR does not propose to allow the generation and use of early NOX emission reduction credits (“ERCs”) but does solicit comment on whether NOX ERCs should be included in the CAIR and, if so, how a NOX ERC program should be structured.

If NOX ERCs are included, EPA expects that they would primarily be generated by sources already subject to the NOX SIP Call that would choose to operate already installed selective catalytic reduction (SCR) technology during the 7-month “non-ozone season.” These reductions in non-ozone season NOX reductions would provide some additional, early environmental benefit by reducing the atmospheric loading of NOX, acid precipitation, and fine PM precursors prior to the implementation of the CAIR. That said, EPA analysis projects that over 3.7 million tons of NOX ERCs could be created (between 2006 and 2010) and banked into the CAIR if unlimited non-ozone season ERCs were permitted in the program. Allowing these ERCs to be used for compliance with the CAIR NOX emission cap would delay progress towards achieving both the annual NOX reduction goals and could potentially reduce the ozone season reductions that are necessary for EPA to justify removing the NOX SIP Call constraint for EGUs.

If EPA were to include ERCs, several approaches could be utilized: (1) EPA could maintain the NOX SIP Call requirements and allow sources to use ERCs only for compliance with the annual limitation, to ensure that seasonal NOX limitations are met. Under this scenario, the additional States subject to the CAIR that have been found to significantly contribute to ozone nonattainment may also have to be included in the ozone season cap; (2) EPA could limit the period of time during which ERCs could be created and banked; (3) EPA could cap the amount of ERCs that can be created; and (4) EPA could apply a discount rate to ERCs.

The EPA solicits comment on today's SNPR to not include NOX ERCs and, if ERCs were included, how the mechanism for including ERCs should be structured.

E. How Would Emissions Trading Under the Proposed CAIR Relate to Regional Haze?

This section addresses the relationship between the CAIR and the CAA visibility-impairment provisions, in particular the Best Available Retrofit Technology (BART) requirements under the Regional Haze Rule. These provisions, under CAA Section 169A-B, require certain existing sources, including electric generating units (EGUs) that may be affected by SIPs required under CAIR, to install BART. However, the Regional Haze Rule further provides that sources otherwise subject to BART may be exempt if they are subject to alternative controls demonstrated to provide greater reasonable progress toward the national visibility goal. Today, EPA proposes that BART-eligible EGUs in any State affected by CAIR may be exempted from BART for controls for SO2 and NOX if that State complies with the CAIR requirements through adoption of the CAIR cap-and-trade programs for SO2 and NOX emissions.

1. Background: Nature of Regional Haze and Visibility Impairment; Statutory and Regulatory Requirements

The EPA has discussed the science and legal background for visibility impairment and regional haze elsewhere, most recently in the re-proposed Guidelines for BART Determinations (69 FR 25184, May 5, 2004). Readers are referred to that preamble for a detailed description of the background. The following is a brief summary.

a. What is regional haze? “Regional Haze” refers to air pollution that impairs visibility over a widespread area that may encompass several States. Regional haze occurs to varying degrees throughout the United States, including at national parks that may be as far as hundreds of miles from major pollution sources.[17] Under sections 169A-B of the CAA, special protection is afforded to larger national parks and wilderness areas, which are termed “Class I areas.”[18]

Visibility in Class I areas, measured as visual range, is observed to be on average one-half to two-thirds of the natural visual range that would exist in the absence of anthropogenic pollution. Start Printed Page 32703Observations show that visibility is lowest in Class I areas in the eastern U.S., and significant impairment in visibility is also observed in the Midwest and on the Pacific coast. The best visibility occurs in the Central Rockies and in Alaska, but even in these locations, visibility is worse than would be expected without anthropogenic pollution.

Most visibility impairment is caused by fine particulate substances and associated water. While natural sources of fine particles, such as forest fires and windblown dust, can affect visibility significantly, anthropogenic emissions are usually the major source of regional haze.[19]

b. Major chemical components of particles that contribute to regional haze; EGUs as the major source of those components. The major chemical classes of fine particles that affect visibility include sulfates, organic matter, elemental carbon (soot), nitrates, and soil dust. The major sources and important aspects of the chemistry of these fine particle components as they affect PM 2.5 mass were summarized in EPA's January 2004 proposal. (69 FR 4566, January 30, 2004).

As discussed in the January 2004 proposal, sulfate particles comprise a major portion of PM2.5 mass. The relative contribution of sulfates to visibility impairment is usually even greater than their contribution to particle mass, largely because sulfates absorb water, which enhances their capabilities to impair.[20] Nitrates, which also generally contribute proportionally more to visibility impairment than they do to fine particle mass, on average caused 5-10 percent of visibility impairment over much of the U.S.[21] Further, as discussed in section II of the January 2004 proposal, the chemical interplay between ammonium sulfate and ammonium nitrate particles is important in determining the effectiveness of SO2 and NOX reductions in reducing fine particles and in improving visibility. Because of this “nitrate replacement,” SO2 controls that reduce sulfates will be more effective at improving visibility if complemented by NOX controls that reduce nitrates, particularly in the winter.

c. Interstate transport and regional haze. A wealth of air quality observations and modeling data clearly demonstrate that PM2.5 and its precursors are transported across State boundaries. This body of evidence—particularly, EPA air quality modeling results—was summarized in the January 2004 proposal. Sulfur dioxide and NOX emissions have been demonstrated to affect ambient PM2.5 concentrations over a wide interstate area. In addition, observations show that sulfate and nitrate make a large contribution to visibility impairment.[22]

A large fraction of current and future SO2 and NOX emissions are attributable to EGUs. In the lower 48 States, the fraction of SO2 emissions from EGUs is a consistent percentage of emissions from all sources, ranging from 62 to 65 percent over time; and EGU NOX emissions as a percent of emissions from all sources is projected to grow slightly from 21 to 25 percent.

d. What are the Clean Air Act requirements for addressing regional haze? In the 1977 CAA, Congress added the first provisions to protect visibility in Class I areas. Subsection (a)(1) of CAA section 169A establishes the following national visibility goal: “The prevention of any future, and the remedying of any existing, impairment of visibility in mandatory Class I Federal areas which impairment results from manmade air pollution.” Subsection (a)(4) of this provision requires EPA to promulgate regulations to assure “reasonable progress toward meeting [this] national goal. * * *” In addition, the CAA visibility provisions contain a specific requirement for the installation of BART at certain existing sources, discussed below.

In 1980, EPA issued regulations addressing visibility impairment “that can be traced to a single existing stationary facility or small group of existing facilities.” (45 FR 80085, December 2, 1980). In that rulemaking, the Agency explicitly deferred national rules addressing regional haze impairment.

In 1990, Congress added section 169B to the CAA to prompt EPA to address regional haze. These provisions specifically establish a commission for Grand Canyon National Park—the Grand Canyon Visibility Transport Commission (GCVTC)—and require the Commission to issue a report to EPA recommending measures to remedy visibility impairment. CAA Section 169B(a)-(d) and (f). In the 1990 CAA Amendments, Congress further provided that within 18 months after receiving this final report, EPA must “carry out the Administrator's regulatory responsibilities under [section 169A], including criteria for measuring ‘reasonable progress’ toward the national goal.” CAA Section 169B(e)(1).

The EPA published a rule in 1999 to address various aspects of regional haze (the Regional Haze Rule). (64 FR 35714, July 1, 1999). The Regional Haze Rule calls for the States to play the lead role in designing and implementing regional haze programs for Class I areas. Each State must establish goals that provide for reasonable progress, over the period covered by the SIP, toward achieving natural visibility conditions in the Class I areas in that State. 40 CFR 51.308(d)(1). States must also submit a long-term strategy, as well as measures necessary to implement that strategy, addressing visibility impairment due to regional haze for each Class I area in the State and for each Class I area located outside the State which may be affected by emissions from the State. 40 CFR 51.308(d)(1), (3).

The EPA provided the States with considerable flexibility in selecting the reasonable progress goals. The Regional Haze Rule requires that these goals both provide for improvement during the 20 percent most impaired days and ensure no degradation in visibility during the 20 percent clearest days. The baseline period for assessing improvement and degradation is 2000-2004. In addition, for each Class I area within its borders, a State must determine the appropriate, annual rate of visibility improvement that would lead to “natural visibility” conditions. The rule includes a presumption that States can reach this goal in 60 years. 40 CFR 51.308(d)(1)(ii). Under the regulations, this 60-year period extends to 2064, with the first long-term strategy period ending in 2018. 40 CFR 51.308(f). States must submit their long-term strategies each 10-year period. The first strategy is due in early 2008 and must provide for reasonable progress through 2018.

The 1999 Regional Haze Rule also addressed the BART requirements, in 40 CFR 51.308(e)(1), and provided for the use of alternative measures in lieu of BART in 40 CFR 51.308(e)(2) (discussed more fully in section III.E.1.e. of this preamble below). The Regional Haze Rule was challenged by several petitioners in the U.S. Court of Appeals for the DC Circuit. American Corn Start Printed Page 32704Growers et al. v. EPA, 291 F.3d 1 (DC Cir., 2002). The Court generally upheld EPA's approach to improving visibility. However, the Court vacated and remanded the provisions of the rule addressing the determination of BART on a case-by-case basis.

In addition to these nationally applicable reasonable progress requirements, the Regional Haze Rule contains a special rule for the nine-State region [23] (including tribes) included in the GCVTC, with respect to the Grand Canyon and 15 other Class I areas located on the Colorado Plateau. Under this provision, these States (and tribes) may meet their reasonable progress requirements for the first, long-term strategy period (ending in 2018) with respect to these 16 Class I areas either by (i) meeting the nationally applicable reasonable progress requirements (40 CFR 51.308), or (ii) adopting the recommendations of the GCVTC, once those recommendations were approved by EPA. 40 CFR 51.309. This section also provided that, before the GCVTC recommendations could be approved, an “Annex” to those recommendations pertaining to stationary sources must be submitted to EPA, providing quantitative emissions reduction goals and detailed implementation strategies. The successor organization to the GCVTC—the Western Regional Air Partnership (WRAP)—submitted such an Annex in September, 2000, and EPA approved it in a final rule by notice dated June 5, 2003. (68 FR 33764).

e. Statutory and regulatory background for BART requirement. Under CAA Section 169A(b)(2)(A), an existing source must install BART if the source was constructed between 1962 and 1977,[24] falls within one of 26 categories, has a potential to emit 250 tons or more of any pollutant, and emits “any air pollutant which may reasonably be anticipated to cause or contribute to any impairment of visibility” at a Class I area. The 1999 Regional Haze Rule, among other things, established requirements for implementing BART on a source-by-source basis, in order to address the contribution of BART-eligible sources to regional haze. 40 CFR 51.308(e)(1).

In addition to requirements for implementing BART on a source-by-source basis, the 1999 rule provides States with an option of using an emissions trading program or alternative measure in lieu of requiring source-by-source BART. 40 CFR 51.308(e)(2). States may utilize this trading or alternative option if they demonstrate that it would achieve greater reasonable progress than source-by-source BART. To make this demonstration, States would compare the estimated emissions reductions available from requiring BART on all BART-eligible sources, and the resulting degree of visibility improvement expected. Under the existing section 308(e)(2) States would also have to ensure that the trading or alternative measure applied to all BART-eligible sources in all 26 categories, within the State.[25]

In July 2001, we proposed guidelines for implementing BART on a source-specific basis. These guidelines also contained guidance on how to demonstrate that a proposed alternative to BART would result in greater progress than source-specific BART. (66 FR 38108, Friday, July 20, 2001).

By notice dated May 5, 2004, we re-proposed the BART regulations and guidelines, to comport with the court's findings regarding source-specific BART. The portions of the BART guidelines related to demonstrating that an alternative is better than BART are largely unchanged from the 2001 proposal. (69 FR 25184, 25186).

2. What Is the Basis for This SNPR That the Cap-and-Trade Program is “Better Than BART” for Affected EGUs?

In today's SNPR, EPA proposes to apply the better-than-BART requirements to the CAIR proposal, as it may affect the 29 States and DC in the eastern part of the country. Specifically, EPA proposes 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 programs for SO2 and NOX for affected EGUs.

a. Better-than-BART two-pronged test. In our recently re-proposed Guidelines for BART Determinations, we propose a methodology for determining whether a trading program will provide greater reasonable progress than BART. If the geographic distribution of emissions reductions is similar under either program a State may demonstrate the trading program is better than BART by showing that the trading program achieves greater emissions reductions than the source-specific BART program. If it is expected that the trading program would result in a different geographic distribution of emissions reductions than would source-specific BART, visibility impacts must be assessed through a two-pronged test. (69 FR 25184, 25231, May 5, 2004). Although under CAIR the total emissions reductions are greater than source-specific BART would achieve in the CAIR States, our modeling indicates that CAIR would produce greater emissions reductions than BART in most States, but lesser reductions in a few States. Because of this potential for a different geographic distribution of emission reductions, we have assessed the difference between the two programs under the two-pronged visibility impact test.

The first prong is designed to address the “prevention of any future” impairment element of the CAA section 169A(a)(1) national visibility goal. Under this prong, visibility must not decline at any Class I area, as determined by comparing the predicted visibility impacts at each affected Class I area under the trading program with existing visibility conditions. This prong also protects against the creation of visibility impairment “hot spots” that could conceivably occur as the result of local emissions increases under a trading program.

The second prong of the test is designed to address the “remedying of any existing” impairment element of the CAA section 169A(a)(1) national visibility goal. Under this prong, at the end of the first long-term strategy period in 2018, overall visibility, as measured by the average improvement at all affected Class I areas, must be better under the trading program than under source-specific BART.

We also note that the two-pronged test does not require that the comparison be limited to BART-eligible sources affected by the alternative-to-BART programs. In other words, one way the alternative program may be better than source-specific BART is by controlling emissions from non-BART eligible sources within the affected source categories. This was the case in our approval of the WRAP Annex as better than BART under Regional Haze Rule section 40 CFR 51.309. (See 68 FR 33769).

b. Application of the two-pronged test to the CAIR proposal. To determine whether CAIR is better than BART, the analysis must address the two main elements of the test. First, we compare the existing visibility situation (using data from the baseline period 2000-2004) to a future where CAIR is in effect to see if any degradation occurs. Second, we compare the visibility Start Printed Page 32705improvements resulting from the CAIR cap-and-trade program to visibility improvements expected from the application of source-specific BART in 2015, near the end of the first long-term strategy period in 2018.

In applying the two prongs of the test, we faced some shortcomings in currently available modeling. Under both prongs, we would ideally perform air quality modeling for the situation where CAIR is in effect only in the CAIR region, and source-specific BART is in effect in the rest of the country. This would reflect the best currently available prediction of future emissions, because BART is a federally enforceable requirement of the CAA, and therefore appropriately assumed to be in effect outside the CAIR region.[26]

However, the CAIR air quality modeling was based on the simplifying assumption that SO2 emission reductions would be required nationwide and did not include BART SO2 controls in place for the non-CAIR region. Additionally, NOX was controlled in a 311/2 State region rather than the 29 State region that is covered in the proposed CAIR.[27] Finally, because the recently re-proposed BART guidelines are applicable nationally, for that rulemaking we estimated emissions after application of source-specific BART on a nationwide basis. We therefore currently lack modeling of a scenario where BART is applied only outside the CAIR region.

Despite these limitations in currently available modeling, we believe the ideal scenario and the modeling we conducted using available information are similar enough to serve as the basis of this “better than BART” determination. In fact, we anticipate that when we model a scenario combining CAIR requirements in the CAIR region with source-specific BART in the rest of the country, we will project fewer SO2 and NOX emissions than our current modeling indicates. The full rationale for this belief is given in a technical support document (SAQMTSD)[28] . The remainder of this section gives a brief overview of key aspects of the methodology we used and the results.

We used the Integrated Planning Model (IPM) to estimate emissions expected after implementation of a source-specific BART approach and after implementation of the CAIR cap-and-trade programs for EGUs. This analysis indicates that implementing BART on a source-specific basis would result in SO2 emissions falling to approximately 6.9 million tons nationally in 2015, then increasing, thereafter [29] . Under the CAIR trading program, however, SO2 emissions in 2015 would fall to about 5.3 million tons nationwide, and would continue declining to 4.3 million tons in 2020 [30] . Notably, CAIR leads to SO2 emission reductions when it starts in 2007 that grow over time. Nationwide, NOX emissions under a source-specific BART approach would be reduced to 2.7 million tons per year in 2015 and do not decrease thereafter [31] , while under the proposed CAIR trading program NOX emissions would be 2.2 million tons nationwide in 2015 and 2.3 million tons in 2020.[32] Notably, substantial NO reductions actually begin in 2010 under the CAIR rule.

We then used the REMSAD air quality model [33] to project the visibility impact of these IPM emissions predictions for both the CAIR and the nationwide source-specific BART scenario. Specifically, EPA evaluated the model results for the 20 percent best days (that is, least visibility impaired) and the 20 percent worst days at 44 Class I areas.[34] These 44 areas are broadly representative of national visibility conditions, as they are found in States throughout the country, including California and Texas, States on the continental divide, the Pacific Northwest, the Southwest, the Southeast, the Mid-Atlantic, and New England. Thirteen of these Class I areas are within States affected by the CAIR proposal, and 31 Class I areas are outside the CAIR region—29 in States to the west of the proposed CAIR region, and 2 in New England States northeast of the CAIR region. We also modeled expected visibility for the future base case, which has lower emissions than we have today overall (that is, we examined expected emissions levels in 2015 without either BART or the trading program, but including emissions reductions anticipated from other requirements.) This is a more stringent way of considering degradation, given we are primarily concerned about degradation relative to the existing visibility situation.

i. First prong: Visibility will not decline at any class I area. The modeling predicts that the CAIR cap-and-trade program will not result in degradation of visibility, compared to existing visibility conditions, at any of the 44 Class I areas considered. In each of the 44 areas—the 13 within the proposed CAIR region and the 31 outside of it—visibility is expected to improve or at worst remain unchanged. Details of these results, for the 20 percent worst days and the 20 percent best days are contained in SAQMTSD. We only had modeling representing nationwide SO2 emission reductions, including some Start Printed Page 32706relatively small amount of SO2 emission reductions occurring in the West [35] . Since the western SO2 emissions reductions are relatively small, EPA believes they will not significantly impact the conclusions of this analysis.

Based on these results and other analysis presented in the SAQMTSD, we believe the CAIR impact on emissions passes the first prong of the two-pronged test by not causing degradation of visibility at any Class I area.

ii. Second prong: Average visibility for all affected Class I areas will improve. The second prong of the better-than-BART test is to analyze whether the CAIR cap-and-trade programs result in greater overall improvement in visibility, as compared to source-specific BART.

For Class I areas in the proposed CAIR region, our analysis indicates that proposed CAIR emissions reductions in the East produce significantly greater visibility improvements than source-specific BART. Specifically, for the 15 Eastern Class I areas analyzed, the average visibility improvement (on the 20 percent worst days) expected solely as a result of the CAIR is 2.0 deciviews (dv), and the average degree of improvement predicted for source-specific BART is 1.0 dv. Therefore, the proposed CAIR is substantially better than BART—indeed, the proposed CAIR provides more than twice the visibility improvement benefits—for Eastern Class I areas.[36]

Similarly, on a national basis, the visibility modeling shows that for the 44 class I areas evaluated, the average visibility improvement, on the 20 percent worst days, in 2015 was 0.7 dv under the proposed CAIR cap-and-trade programs, but only 0.4 dv under the source-specific BART approach.

We therefore believe that these results, in combination with the other analysis in the SAQMTSD, demonstrate that the second prong of the better-than-BART test is met.

Because both prongs of the test are met, EPA proposes to conclude that the proposed CAIR cap-and-trade program is better than BART for BART eligible EGUs within the proposed CAIR region. Therefore, States that adopt the model cap-and-trade programs would not be required to implement source-specific BART for their EGUs.

3. What Changes to the Regional Haze Rule Provisions for Alternatives to BART Are Proposed?

The preceding discussion applied the provisions of section 40 CFR 51.308(e)(2) of the Regional Haze Rule which allows States to determine that a trading program or other alternative measure may be substituted for individual BART applications for all sources subject to the BART requirement.

Because the proposed CAIR allows States to choose how to achieve the required emissions reductions, and does not mandate participation in the EPA-administered cap-and-trade program for EGUs, some States may wish to satisfy their proposed CAIR requirements through controls on sources other than EGUs, or through controls on EGUs without using the CAIR cap-and-trade programs (such as through an in-State only trading program). To the extent that these control obligations fall on BART-eligible sources, the State may wish to demonstrate that these controls are better than BART, and therefore satisfy the source-specific BART requirements for those sources.

To accommodate the various approaches States may wish to take in complying with the proposed CAIR and making the better-than-BART determinations, we propose to add a new section to the alternative-to-BART provisions of the Regional Haze Rule. We are not proposing to change or revise the provisions contained in section 308(e)(2), which apply to States that develop their own cap-and-trade program or other alternative measure to BART. Therefore, we are retaining 308(e)(2) without revision, except for the addition of a proposed cross-reference to the new provision for these BART-alternative rules proposed today. Section 308(e)(2) will continue to apply to trading programs or other alternatives to BART which do not involve the proposed CAIR cap-and-trade programs. These might include in-State only trading programs, or future regional trading programs developed by States and tribes through Regional Planning Organizations.

We propose to add a new section 308(e)(3), which provides that for any of the 29 States and DC in the CAIR region, implementation of the CAIR cap-and-trade programs to fulfill the proposed State emissions reduction obligations under the CAIR qualifies as a “better than BART” alternative. This alternative is available only to States that subject all of their EGUs to the cap-and-trade programs. As explained above, modeling to support the proposed determination establishes that the cap-and-trade programs would result in greater reasonable progress than would source-specific BART for EGUs. Therefore, a better-than-BART demonstration would not be required of States that choose this option.

We also propose to renumber current sections 308(e)(3) and (4) to read 308(e)(4) and (5), respectively. These sections provide for continuing regulation of BART-eligible sources under the general regional haze provisions after BART is satisfied, and for source-specific exemptions from the Administrator.

4. What Effect Does the CAIR Cap-and-Trade Program Have on Source-specific BART Based on Reasonably Attributable Visibility Impairment?

As we explained in our recent re-proposal of the BART guidelines (69 FR 25184, May 5, 2004), when a State utilizes an alternative measure such as an emissions trading program in lieu of requiring BART on specific sources, the requirement for BART is not satisfied until the alternative measure reduces emissions sufficiently to make “more reasonable progress than BART.” Thus, in that period between implementation of an emissions trading program and the satisfaction of the overall BART requirement, an individual source could be required to install BART for reasonably attributable impairment under 40 CFR 51.302. The Regional Haze Rule contains a provision allowing for “geographic enhancements” to address the interface between a regional trading program and the requirement under 40 CFR 51.302 regarding BART for reasonably attributable visibility impairment. (See 40 CFR 51.308(e)(2)(v)).

We note that the same framework applies in the context of the proposed CAIR cap-and-trade programs. That is, until the emissions reductions requirements in today's SNPR are fully implemented in 2015, the possibility exists that a certification of impairment by a Federal Land Manager (FLM) could trigger a requirement for a State to determine whether the impairment is “reasonably attributable” to a single Start Printed Page 32707source or small group of sources, and if so to make a source-specific BART determination. We request comments on whether a “geographic enhancement” (for example, an adjustment to the State's allowance budget) would be appropriate, and whether such enhancement mechanisms should be determined by EPA on a national basis, or individually by affected States.

We also note that the WRAP, as part of its voluntary emissions milestones and backstop SO2 cap-and-trade program under Regional Haze Rule section 309 has adopted policies which target use of the § 51.302 provisions by the FLMs. In this case, for the five States in the WRAP program, the FLMs have agreed that they will certify reasonable attributable impairment only under certain specific conditions. Under this approach, the FLMs would certify under 40 CFR 51.302 only if the regional trading program is not decreasing or has not decreased sulfate concentrations in a Class I area within the region. Moreover, the FLMs will certify impairment under 40 CFR 51.302 only where: (1) BART-eligible sources are located “near” that class I area and (2) those sources have not implemented BART controls. In addition, the WRAP is investigating other procedures for States to follow in responding to a certification of reasonably attributable impairment if an emissions trading approach is adopted to address the BART requirement based on the sources' impact on regional haze.

We request comment on whether such an approach would be appropriate for the proposed CAIR cap-and-trade programs.

F. Tribal Issues

As discussed in our January 2004 proposal, tribal implementation of approved CAA programs is optional. That is, under CAA section 301(d) as implemented by the Tribal Authority Rule (TAR), eligible Indian tribes may implement all, but are not required to implement any, programs under the CAA for which EPA has determined that it is appropriate to treat tribes similarly to States. Tribes may also implement “reasonably severable” elements of programs. (40 CFR 49.7(c)). In the absence of tribal implementation of a CAA program or programs, EPA will utilize Federal implementation for the relevant area of Indian country as necessary or appropriate to protect air quality, in consultation with the tribal government. State implementation plans are generally not applicable in Indian country.

With very few exceptions, Indian country is not home to the types of air pollution sources potentially affected by this rule—neither EGUs, nor other large sources of NOX or SO2 that could be controlled in order to meet emission reduction requirements.

Despite these legal and factual considerations which indicate that today's proposal would not generally immediately affect tribes, tribes have raised valid concerns about the rule's future implications. These implications arise from the fact that the cap-and-trade program by definition is designed to cap emissions over a broad geographic area and constrain these emissions into the future. Indian country lands are included within these broad areas. Some tribes may choose to pursue a path of economic development which may include future sources of air pollution.

The TAR contains a list of provisions for which it is not appropriate to treat tribes in the same manner as States. 40 CFR 49.4. The CAIR proposal is based on the States' obligations under CAA 110(a)(2)(D) to prohibit emissions which would contribute significantly to non-attainment in other States due to pollution transport. Because CAA 110(a)(2)(D) is not among the provisions we determined to be not appropriate to apply to tribes in the same manner as States, the CAIR is applicable to tribes. However, among the CAA provisions not appropriate for tribes are “[s]pecific plan submittal and implementation deadlines for NAAQS-related requirements * * *” 40 CFR 49.4(a). Therefore, tribes are not required to submit implementation plans under the CAIR. Instead, the CAIR will be implemented as necessary or appropriate in Indian country, either through voluntary Tribal Implementation Plans or Federal Implementation Plans developed in consultation with affected tribes.

The EPA believes new sources that locate in Indian country should be subject to the program in the same manner as any new source located outside of Indian country. If they were not, emissions from new Indian country sources could jeopardize the environmental goals of PM2.5 and ozone attainment on which today's rule is based. It could also conceivably result in undue pressure for energy and economic development in Indian country, depending on allowances, prices and a variety of other economic and regulatory factors.

At the same time, some tribal representatives have voiced another set of concerns to EPA. In their view, requiring new sources in Indian country (which may be tribally owned) to either obtain an allocation of allowances from the State where the tribe is located, or to purchase allowances in order to operate is unfair, for several reasons. These include: (1) That the concept that budgets for Indian country should be derivative from State budgets may offend notions of tribal sovereignty and autonomy; (2) that Federal policy over the course of U.S. history has hindered tribal economic development and this inequity should not be continued by basing allocations on existing source emissions; (3) that some of the tribes that have contributed substantially to the economy through extractive industries have not shared in the economic benefits, including residential electrification; and (4) that Indian country areas may have suffered the detrimental effects of air pollution from the sources from which they would be required to buy allowances in order to construct new sources.

One approach that might be used to address these concerns would be to develop a Federal set-aside of allowances for new sources in Indian country. The WRAP, in developing a backstop cap-and-trade program for SO2 under section 40 CFR 51.309 of the Regional Haze Rule, addressed this same set of concerns. The WRAP is a unique partnership of 13 western States, tribes, and Federal agencies. The WRAP Board comprises equal numbers of State governors and tribal leaders, or their designees, and decisions are made by consensus.

Based on tribal input, the WRAP included provisions to address the tribal concerns delineated above including a tribal set-aside of 20,000 tons of SO2 per year. This amount was not the product of any single formula, but was negotiated within the WRAP based on a number of factors. One important consideration was that because new EGUs and other major sources would be subject to pre-construction permitting under New Source Review (NSR) or Prevention of Significant Deterioration (PSD) rules, as well as New Source Performance Standards (NSPS) or Maximum Achievable Control Technology (MACT), SO2 emissions per MW or other unit of production would be considerably lower than for older, less efficient plants. Therefore, although 20,000 tons represents only about 4 percent of the 9-State cap for 2018, it would enable the installation of a much larger percentage of new capacity.

The WRAP's cap-and-trade program will only come into existence if voluntary efforts and current requirements fail to meet the agreed upon emissions reduction “milestones.” Therefore, the tribal set-aside, like all tradable allowances under this program, Start Printed Page 32708will only exist if the milestones are not met sometime between 2003 and the end of the first long-term strategy period in 2018. In light of the uncertainty of this event, and of the difficulty of reaching consensus among the more than 200 tribes in the affected region, the WRAP did not attempt to establish the mechanism by which the tribal set-aside would be allocated among tribes. Rather, it was agreed that this mechanism would be determined within one year of the date the trading program was triggered, by a determination that the milestones had been exceeded. This would provide for the distribution of all allowances by the time of trading program implementation.

Tribal participants in the WRAP stipulated that the tribal set-aside allocations would be available to tribes for use by new sources, for sale to generate revenue, or to retire for the benefit of the environment. The EPA concurred with these uses in the preamble to the final WRAP Annex rule (68 FR 33778, June 5, 2003). We also agreed that tribal participation in the Annex, including the tribal set-aside, is not dependent on whether the State in which the tribe is located participates. For the few sources currently in existence in Indian country within the WRAP region which are eligible for the program based on SO2 emissions, the WRAP would provide for allowance allocations within the existing-source cap. These sources would not need to draw upon the tribal set-aside for the allowances to cover their emissions.

There are no emission sources in Indian country of which we are aware in the 29-State region that could be affected by the January 2004 proposal. (We request comment regarding the existence of any such sources of which we are unaware). Therefore, the only way tribes in this region could receive allowances would be through a set-aside.

The approach used by the WRAP could provide a template for the CAIR for both SO2 and COX set-asides for tribes. This would raise a number of issues, some identical to those faced by the WRAP and some with different considerations. For example, one difference is that because the CAIR is not a backstop cap-and-trade program, any allowance set-aside for tribes would either result in a corresponding decrease in the present allowances of existing sources, or increase the overall level of the cap.

The WRAP example of establishing a tribal set-aside provides one possible approach to addressing tribal concerns. If EPA were to determine that a tribal set-aside were appropriate, some issues raised in developing the set-aside would include: (1) What method to use to determine the SO2 and NOX set-asides, for example through negotiation or by a formula, (2) whether the set-aside would be in addition to or part of the allocations proposed in our January 2004 proposal, and (3) how the tribal set-aside would be allocated or distributed among tribes, for example on a first-come first-served basis, by an allocation formula, or some combination of approaches.

We seek comment on whether a tribal set-aside is necessary or appropriate; if so, how it should be structured; whether other approaches might better address the tribal concerns identified above. We also seek comment on any other implications the proposed CAIR may have for tribes. We remain committed to fulfilling our obligation to consult with tribes, and will continue to do so as we address these issues.

IV. Model Cap-and-Trade Rule

A. Background and Purpose of the Model Rules

This section of today's action proposes model trading rules—one for SO2 and one for NOX—that States will adopt if they wish to participate in the EPA-managed, EGU cap-and-trade program to achieve the emissions reductions of the proposed CAIR. This fulfills the commitment made in the January 2004 proposal.

Today's action proposes a NOX and a SO2 model cap-and-trade rule for public comment. At the time of signature of today's SNPR, EPA had not yet reviewed full public comment on the January 2004 proposal, which solicited comment on some model rule concepts. The EPA intends to respond to comments received on the January 2004 proposal and today's SNPR when it promulgates the final rule.

The NOX and SO2 model rules incorporate the experience gained through the implementation of several cap-and-trade programs (i.e., the CAA title IV SO2 Acid Rain Program, the Ozone Transport Commission Regional NOX Program, and the NOX SIP Call), lessons learned from other trading programs like the Regional Clean Air Incentives Market (RECLAIM), as well as two workshops which EPA held to inform this rulemaking. These workshops, held in July and August of 2003, provided a forum for States and multi-State air planning organizations to share with EPA what has worked well, what may not have worked well, and what could be improved. (The EPA Web site provides a summary of the comments received from these workshops at http://www.epa.gov/​airmarkets/​business/​noxsip/​atlanta/​atl03.html). Workshops such as these played an important role in the development and implementation of the NOX SIP Call and aided in the development of this proposed rule.

This section describes: The advantages of adopting the model trading rules; the requirements for those who choose to adopt the model rules; the flexibility that States have in developing their cap-and-trade rules; and, lastly, a subpart-by-subpart explanation of the model rule provisions that highlights key elements and aspects unique to either the SO2 or NOX programs.

1. Who May Adopt the Model Rules and What Are the Advantages of Adopting New Model Rules?

States may choose to participate in the EPA-managed cap-and-trade programs, which are a fully approvable control strategy for achieving all of the emissions reductions required under today's proposed rulemaking, in order to achieve the mandated emission reductions in a highly cost-effective manner. States that wish to reduce emissions by controlling EGUs (which modeling shows can make additional highly cost-effective emission reductions) through a regionwide cap-and-trade approach may simply adopt the model rules and comply with the requirements for Statewide budget demonstrations detailed in section III. States that elect to achieve the required reductions by regulating other sources or using other approaches, should refer to section III for alternate State requirements.

Today's action proposes that States that choose to achieve the mandated emission reductions through the EPA-managed cap-and-trade programs are also required to adopt both the SO2 and NOX model rules. Requiring States to participate in both the SO2 and NOX programs assures that compliance is more readily determinable, and creates incentives for sources to develop comprehensive control strategies for both pollutants.[37]

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Advantages of Adopting the Model Rules

EPA is proposing the use of regionwide cap-and-trade programs because market-based approaches have proven to be both environmentally effective and cost-effective. The advantages of a well-designed cap-and-trade system include:

  • Control of emissions to desired levels under a fixed cap that is not compromised by future growth;
  • High compliance rates;
  • Lower cost of compliance for individual sources and the regulated community as a whole;
  • Incentives for early emissions reductions;
  • Promotion of innovative compliance solutions and continued evolution of electricity generation and pollution control technology;
  • Flexibility for the regulated community (without resorting to waivers, exemptions and other forms of administrative relief that can delay emissions reductions);
  • Direct legal accountability by sources for compliance;
  • Coordinated program implementation that efficiently applies administrative resources while enhancing compliance; and
  • Transparent, complete, and accurate recording of emissions.

These benefits result primarily from the interplay of a rigorous cap-and-trade framework, flexibility in compliance options, and the monetary incentives associated with avoided emissions in a market-based system. The model rules are designed around elements that are essential to a successful cap-and-trade program. These include:

  • Simplicity (e.g., clear applicability thresholds, allocation formulas, trading rules and restrictions, measurement options and procedure, reporting requirements, and penalty assessment);
  • Accountability (e.g., accurate measurement of emissions, complete and timely emission reporting, and automatic penalties for noncompliance);
  • Transparency (e.g., full and open disclosure of programmatic elements, compliance data, allowance ownership, and environmental progress); and
  • Predictability and Consistency (e.g., to provide consistent program implementation over time and a long compliance planning horizon that allows long-term, innovative strategies).

States collectively benefit from the adoption of the model rules by improving the efficiency and clarity of the CAIR's implementation.

In addition, States adopting the CAIR NOX and SO2 model rules will benefit from improvements to the rule mechanics that originated from the stakeholder input during the implementation of the Title IV, OTC, and NOX SIP Call cap-and-trade programs, as well as the EPA-managed “lessons learned” workshops held in 2003. Today's proposed NOX and SO2 model rules not only incorporate these refinements, but are designed to parallel the existing rules in parts 96 and 97 (see sections IV.A.4 and IV.B below) to allow States that have already codified all or part of these regulations to transition smoothly into both the CAIR NOX and SO2 programs.

2. Requirements for Adopting the Model Cap-and-Trade Rules

Except as noted in section IV.A.3, States that choose to participate in the EPA-managed cap-and-trade programs must adopt the complete model cap-and-trade rules in order to participate in the program and to have it constitute an approvable remedy for achieving the mandated SO2 and NOX emission reductions. (Section III discusses the requirements for States, including those that wish to comply with the CAIR through alternatives other than the EGU-based emission reduction approach proposed in today's action.) This ensures that all participating sources, regardless of which State in the CAIR region they are located, are subject to the same rules. Further, requiring States to use the complete model rules provides for accurate and certain quantification of emissions, which are—when reflected in allowances—a valuable commodity on the trading market, and thereby maintains the financial integrity of the allowance trading market. In turn, the integrity of this emissions measurement system and the trading market ensures that the environmental goals are met.

States are required to achieve all of the mandated emissions reductions from large EGUs if they wish to participate in the EPA-managed cap-and-trade programs. (In other words, States that achieve all or part of the emissions reductions from large non-EGUs, may not participate in the EPA-managed cap-and-trade programs.) More specifically, the rules must apply to all fossil fuel-fired boilers and turbines serving an electrical generator with a nameplate capacity greater than 25MW and producing electricity for sale (except for certain cogeneration units). All units that meet this generation size threshold would be affected by the proposed CAIR with no exemptions for small, low-emitting units. (The EPA is not proposing an exemption for units that meet the generation applicability threshold but emit less than 25 tons of NOX, as done in the NOX SIP Call.) The EPA anticipates that these small, low-emitting units will take advantage of special monitoring and reporting procedures in part 75 that simplify the requirements for low mass emitting (“LME”) units. In general, these procedures relieve much of the administrative burden and, therefore, compliance costs, for LME units by allowing them to use conservative emissions estimates in lieu of continuous emissions monitoring. In providing streamlined monitoring and reporting options, EPA can accurately and cost-effectively account for the emissions, even at low emission levels, and allow them to participate in the cap-and-trade programs.

Sources that produce usable thermal energy, such as steam, in addition to generating electricity are known as “cogeneration units.” Only a cogeneration unit that (i) serves a generator greater than 25 MW, (ii) sells at least 1/3 of its potential electrical output capacity and at least 25 MW of electricity, and (iii) meets certain operating and efficiency criteria is considered an EGU and covered by the EPA-managed cap-and-trade programs. (See section IV.B.1 for a proposed clarification to the definition of a cogeneration unit.)

Once a unit is classified as an EGU for purposes of this rule, the unit will remain classified as an EGU regardless of any future modifications to the unit. If a unit serving a generator that initially does not qualify as an EGU (based on the nameplate capacity) is later modified to increase the capacity of the generator to the extent that the unit meets the definition of EGU, this unit will become an EGU for purposes of this rule. This approach is proposed to prevent avoidance of regulation by initially constructing units that are below the size threshold, and then upgrading above the size criteria.

3. Flexibility in Adopting the Model Cap-and-Trade Rules

It is important to have consistency from State-to-State when implementing a multi-State cap-and-trade program to ensure that the intended emissions reductions are achieved and that the compliance and administrative costs are minimized. However, EPA believes that some differences, such as allowance allocation methodologies for NOX allowances, are possible without jeopardizing the environmental goals of the program.

a. Allocation of NOX and SO2 allowances. Each State participating in the EPA-managed cap-and-trade Start Printed Page 32710programs must develop a method for allocating, or distributing, (to the extent that the State has allowances available to allocate) NOX allowances equal to its CAIR EGU budget. For NOX allowances, States have the flexibility to allocate their EGU NOX budget to individual units however they choose. For SO2, as noted in the approach outlined in the January 2004 proposal, States do not have discretion in their allocation approach since the proposal relies on title IV SO2 allowances which have been already allocated in perpetuity to individual units by title IV of the CAA. Today's action proposes essential elements that would be required for each State's NOX allocation method (e.g., the deadlines by which each State must complete and submit to EPA their unit-by-unit allocations for inclusion into the electronic data systems), describes areas in which States have flexibility, and provides an example allocation approach.

i. Aspects unique to SO2 allowance allocations. The CAIR SO2 allocations differ from the NOX approach because the title IV SO2 allowances—the proposed basis for the CAIR—have already been allocated in perpetuity to specific units. Only units that were listed or described in the 1990 CAA Amendments are allocated allowances. Some units that are currently affected by the today's proposed rule title IV Acid Rain Program are not allocated title IV SO2 allowances and instead must acquire all of the allowances they need in the marketplace.

ii. Required aspects of a State allocation approach. While it is EPA's intent to provide States with as much flexibility as possible in developing allocation approaches, there are some aspects of State allocations that must be consistent for all States. Today's SNPR proposes that all State allocation systems are required to include specific provisions that establish when States notify EPA and sources of the unit-by-unit allocations. These provisions would create: (1) The minimum lead-time for a State to notify a source of its allocations; and (2) the deadline for each State to submit to EPA its unit-by-unit allocations for processing into the electronic data systems.

Today's action proposes to require States to submit unit-by-unit allocations no less than 3 years prior to January 1 of the allowance vintage year. Requiring States to provide a minimum amount of notification ensures that an affected source—regardless of the State in the CAIR region in which the unit is located—would have sufficient time to plan for compliance. Finalizing allowance allocations less than 3 years in advance of the compliance year may reduce a CAIR unit's ability to plan for compliance and, consequently, increase compliance costs. Shorter notification periods may also prevent CAIR units from participating in allowance futures markets, a mechanism for hedging risk and lowering costs. (Note: New units will not have allowances 3 years in advance of their first year of operation.) In addition, States would be required to submit the unit-by-unit allocations to EPA by a specific date for sources in their State. This allows EPA to efficiently administer the program and ensure a fair and competitive market for allowances across the region.

These minimum requirements would apply to the NOX allocation approach and would not be relevant for SO2, which relies on title IV allowances.

iii. Flexibility and options for a state allowance allocations approach. Allowance allocation decisions in a cap-and-trade program are largely distributional issues, as economic forces would be expected to result in economically efficient and environmentally similar outcomes. Consequently, for CAIR NOX allowances, States would be given latitude in developing their allocation approach. Allocation methodology elements for which States will have flexibility include:

  • The cost of the allowance distribution (e.g., free distribution or auction);
  • The frequency of allocations (e.g., permanent or periodically updated);
  • The basis for distributing the allowances (e.g., actual heat-input or actual power output); and,
  • The use of allowance set-asides (e.g., new unit set-asides or energy efficiency set-asides).

These points are discussed immediately below.

Cost of Allowance Distribution

Allowances may be distributed by either providing them at no cost (i.e., a “free distribution”), offering them for sale to bidders (i.e., an “auction”), or some combination of the two. Today's proposal allows the State to decide which approach is best for their circumstances.

Auctions: In general, auctions ensure all parties, including the general public, have access to allowances and are considered to be economically efficient since sources would bid their perceived values for allowances. It is possible to auction all allowances under a cap, or have a hybrid approach that auctions some portion of the pool that could change over time. The title IV Acid Rain Program is an example of a hybrid in that it reserves 2.8 percent of available allowances for an auction and distributes the remainder for free. Auctions may also vary in the frequency with which they are held. Strict procedures must be established for auctions and, in the context of the proposed CAIR, States would be responsible for implementing these rules. Allowance auctions are typically, but are not required to be, open to any person, including sources or third-party entities, that can comply with the auction protocols. (In general, auction protocols establish key procedures for bidding, the bidding schedule, a bidding mechanism, and requirements for financial guarantees.)

Auctions treat existing and new sources in a similar fashion. Sources performing costly retrofits to reduce emissions would then also have to pay for allowances for their remaining emissions. Some other benefits of auctions include the fact that they eliminate the permanent right to emit and can provide distortion-free revenues to States.

Free Distribution: A free distribution system provides allowances to any entity, typically the affected sources, as determined by the State. When using a free distribution, it is necessary to establish both (1) the basis for determining each unit's share of the allowance pool, and (2) the frequency with which the allowances are allocated. The title IV Acid Rain Program is an example of a free, one-time distribution (with a small percentage reserved for auction, as mentioned above) that uses the product of historical heat input and specified emission rates (i.e., a permanent, heat input-based system) to determine each unit's share of the pool.

Allocating allowances for free could lessen the financial impact of the program on the affected sources which already bear the compliance costs, but would not be expected to affect the sources' output decisions, or labor and pricing decisions. It would also give States the ability to determine the initial allowance recipients.

Frequency of Allocating Allowances

Allowances may be allocated once (i.e., a “permanent” allocation) or periodically recalculated (i.e., “updated”) based upon some protocol. When deciding upon the frequency of the allocations, any of the options concerning the cost of distribution and the basis for apportioning the pool may be used. However, it is important to consider the practical implications of using complex protocols, such as data that must undergo time-consuming Start Printed Page 32711quality assurance, when frequently updating.

Permanent Systems: Permanent systems allocate all of the allowances at the beginning of the program. They provide long planning horizons for affected sources that receive an allocation.

Permanent allocations do not create additional incentives for those units that receive allowances to change their future behavior to garner more allowances (e.g., increase utilization). Furthermore, because permanent systems are based on a historic baseline, they would not reflect changes in the industry going forward. For instance, retired units would continue receiving allowances. Additionally, a pure permanent allocation system would not provide for allowances to new affected units that begin operations after the allocation of allowances and instead would require them to obtain allowances from the market. The title IV Acid Rain Program is an example of a primarily permanent approach that auctioned 2.8 percent of the allowances to provide new sources an additional mechanism for obtaining allowances.

Updating Systems: Updating systems periodically recalculate and reallocate allowances. These include: The ability to reflect future changes in the power sector; the ability to impact the future generation mix; and, an inherent mechanism for new generators to gain access to free allowances. An updating system that bases the allowance distribution on power output provides an additional incentive beyond the inherent reward for efficiency provided by the market for existing units to improve their generation efficiency and for new units to employ the most efficient technology available.

Updating methods may provide a slight subsidy for units to either generate (for output-based systems) or consume more fuel (for input-based systems). Should this potential subsidy result in an increase in electricity production, there would be a corresponding slight distortion (lowering) of the price of electricity as well as an incentive for older units to continue generating. (Note that under a capped program, incentives to generate will not impact the total emissions of the capped pollutants.)

There are additional aspects of the allocation frequency that are significant in an updating system. These include:

  • The length of the period for which allocations are determined (e.g., the allocations may be calculated for one year or for 5 years at a time); and
  • The length of the notification time (e.g., allocations are determined and announced 3 years into the future, 5 years into the future).

In general, the longer the allocation period (i.e., the less frequent the updating), the more the system will resemble a permanent approach.

Allowance Set-Asides

Allocation methodologies may include a reserve of a certain number allowances from within the cap to create a “set-aside” of allowances. This reduces the number of allowances available to the existing affected sources. Set-asides may be used for a variety of purposes including encouraging certain behaviors (e.g., demand-side energy efficiency and renewable energy set-asides) and mitigating potential disadvantages in the marketplace (e.g., auction set-asides or, as discussed below, set-asides available to units that come online after the program implementation date). In the context of the proposed CAIR, States (if they choose to have set-asides) would be responsible for developing and implementing protocols to distribute set-asides. Set-asides may have provisions that distribute unused allowances back to affected sources should the set-asides not be fully utilized.

New unit set-asides create a pool of allowances that are available to units that come online after the allowances have been allocated. This may mitigate potential barriers to entering the market for new units. Should a new unit be included in an allocation approach, it is necessary to determine how the allowances will be distributed to the new units from the pool. Common approaches include basing each unit's share on either heat input or power output. Depending upon the type of performance measurement used, slightly different incentives may be created. For example, if the new unit's power output were used to distribute the set-aside, sources would find an additional incentive—beyond the incentive for efficiency inherent in the market—to employ more efficient generation technology. (Note that the allocation example provided below includes a new unit set-aside with a hybrid input/output distribution metric.)

Basis for Determining Share of Allowance Pool

For any allocation option, other than an allowance auction, it is necessary to establish the primary parameter that will be used to determine each unit's share of the allowance pool. This parameter is typically a performance measure such as:

  • Measured or potential emissions (in tons ) from the unit;
  • Historical or current measured heat input (in mmBtu) of the unit; or
  • Measured or potential production output (in terms of electricity generation and/or steam energy) of the unit.

Any of these parameters may be used to distribute allowances, regardless of whether it is a permanent or updated system. Other factors, such as fuel type or emission rates (e.g., pounds of pollutant per mmBtu heat input or pounds of pollutant per MWhr of power output) may be used with the above parameters. As mentioned earlier in this discussion of allocation options, the choice of the parameter for distributing allowances can influence the behavior of affected sources in an updating system.

iv. Example allowance allocation system. Included below is an example (offered for informational guidance) of an allocation methodology that includes allowances for new generation and is administratively straightforward. The method involves input-based allocations for existing fossil units, with updating to take into account new generation on a modified output basis. This methodology is offered as an example, as individual States would make their own choice regarding what type of allocation method to adopt for NOX allowances.

Initial allocations for existing sources could be made for the first control periods at the start of the program on the basis of heat input. After the first 5 years, the budget would be distributed on an annual basis, taking into account data from new units.

As new units enter into service and establish a baseline, they begin to pick up allowances in proportion to their share of the generation. Allowances allocated to existing plants slowly decline as their share of total heat input decreases with the entry of new plants. In this EPA example methodology, existing units as a group would not update their heat input. This would eliminate the potential for a generation subsidy (and efficiency loss) as well as any potential incentive for less efficient units to generate more. This methodology would also be easier to implement since it would not require the updating of existing units' baseline data. Retired units would continue to receive allowances indefinitely, thereby creating an incentive to retire less efficient units.

Through this EPA example methodology, new units as a group would only update their heat input Start Printed Page 32712numbers once—in the initial baseline period when they start operating. This would eliminate any potential generation subsidy and be easier to implement, since it would not require the collection and processing of data needed for regular updating.

The EPA believes that allocating based on heat input data (rather than output data) for existing units is desirable because accurate protocols exist for monitoring this data and reporting it to EPA, and several years of certified data are available for most of the affected sources. This heat input data for existing units could be adjusted by multiplying it by different factors based on fuel-type, reflecting the inherent higher emissions of coal-fired plants. For example, factors could be calculated based on average historic NOX emissions rates by fuel type (i.e., coal, gas and oil) throughout the proposed CAIR region for the years 1999-2002 at 1.0 for coal, 0.4 for gas and 0.6 for oil.

However, allocating on the basis of input for new sources would serve to subsidize less-efficient new generation. For a given generation capacity, the most efficient unit would have the lowest fuel input or heat input. Allocating to new units based on heat input may encourage the building of less efficient units since they would get more allowances than an efficient, lower heat input unit. The modified output approach, as described below, would encourage new, clean generation and would not reward inefficient or higher emitting new units.

Allowances would be allocated to new units on a “modified output” basis. The new unit's modified output would be calculated by multiplying its gross output by a heat rate conversion factor of 8,000 btu/kWh. The 8,000 btu/kWh value for the conversion factor is a mid-point between expected heat-rates for new gas-fired combined cycle plants, new pulverized coal plants, and new IGCC coal plants (based upon assumptions in EPA's economic modeling analysis. See documentation for IPM at http://www.epa.gov/​airmarkets/​epa-ipm/​attachment-h.pdf). In addition, this would create consistent incentives for efficient generation (rather than favoring new units with higher heat-rates). For new cogeneration units, their share of the allowances would be calculated by multiplying (1) the sum of their electric output and one half of their equivalent electrical output energy for the unit's process steam, times (2) 8,000 btu/kWh conversion factor.

Five years after entering the CAIR cap-and-trade programs, new units would be incorporated into the calculations for allocations to all affected units. After 5 years of participating in the cap-and-trade programs, new units would have an adequate operating baseline of heat input data. The average of the highest 3 years from these 5 years would be used to calculate the heat input value that the new unit would use to receive allowances from the pool of allowances for all sources.

In this example, only fossil units would be included in the updating process. This is administratively more straightforward and would comprise the vast majority of expected new generation. Alternately, all new generating units could be included in the updating process, which would provide incentives for all new generation (such as renewables, hydro, nuclear). To include such non-fossil units as part of the program would involve clearly defining the entities which could participate (e.g., application procedures, size requirements, and boundaries of included generation, since there is no clear analog to discrete fossil “units”).

New units that have entered service, but have not yet established a baseline output and have not yet started receiving allowances through the update, could receive allowances each year from a new source set-aside. In this example methodology, EPA has described a new source set-aside representing 2 percent of the State's emission budget.

Allowances in the new source set-aside could be distributed in a number of different ways. For example, as described in today's proposed model rules, the new source allowances could be distributed based on a unit's utilization/output and the unit's NSPS rate limitation as proposed in the Clear Skies Act of 2003. Because the proposed NSPS rates vary across fuel types, this allocation method could provide new plant investors with varying incentives depending upon the fuel type. While this set-aside would help new sources relative to a situation with no set-aside, because the demand for allowances for future sources is unknown, it is difficult to know beforehand what should be the appropriate size of the set-aside pool.

Another potential approach for distributing allowances from a new source set-aside is using a single emissions rate for all new plants and a plant specific utilization or power output level to calculate allowance allocations for new units before they begin receiving allowances through the update. Alternatively, the lower of the NSPS rates for the respective fuel types and a rate representing the proposed caps in 2010 and 2015 divided by projected 2010 and 2015 total affected unit generation may be used to calculate allowance allocations for new units before they begin receiving allowances through the update. This alternative would ensure that new sources would receive allowances at the same rate as that applied to existing sources and no greater than their proposed NSPS. A State may also choose to distribute allowances from this set-aside through an auction, which could be open to anyone or limited (e.g., only new sources could participate). We ask for comment on these various proposals, and for any other alternatives commenters may wish to raise.

In today's proposed example allocation methodology, new units would begin receiving allowances from the set-aside for the control period immediately following the control period in which the new unit commenced commercial operation, based on the unit's actual utilization rates for the preceding control period. States would allocate allowances from the set-aside to all new units in any given year as a group. If there were more allowances requested than in the set-aside, allowances would be distributed on a pro rata basis. Allowance allocations in following years would continue to be based on the prior year's utilization until the new unit is considered an existing unit and is allocated allowances through the State's updating process. This would enable new units to have a good sense of the amount of allowances they would likely receive—in proportion to their generation. This methodology would not provide allowances to a unit in its first year of operation; however this methodology is straightforward and predictable.

As an alternative, States could distribute a new source set-aside for a control period based on full utilization rates. Then, at the end of the year, the actual allowance allocation would be adjusted to account for actual unit utilization/output, and excess allowances would be returned and redistributed, first taking into account new unit requests that were not able to be addressed. This was the example methodology used in the NOX SIP Call model rule. In implementing the NOX SIP Call, EPA found this approach to be complicated for both the States and the Agency in implementing the procedure, as well as to the sources as this approach introduces a higher level of uncertainty in the allocation process than may be necessary.Start Printed Page 32713

With either approach, any unused set-aside allowances could be redistributed to existing units based on their existing allocations. The EPA is soliciting comment on the timing and method of allocating allowances from the set aside in the example methodology.

While EPA recognizes States' flexibility in choosing their NOX allocations method and is proposing that States be allowed to determine their own method for allocating allowances to sources in their State, EPA is also asking for comment on all aspects of this example allocation proposal and whether the proposed regulatory language, which codifies the above example as proposed in today's SNPR, could reflect a different approach.

The EPA is also soliciting comment on alternate allocation methods.

b. Individual unit opt-in. In today's SNPR, EPA is soliciting comment on whether opt-in provisions (i.e., provisions that allow units that otherwise would not be subject to the proposed CAIR to individually elect, or “opt,” to participate in the proposed CAIR cap-and-trade programs) should be included in the final CAIR rule. Further, EPA provides and solicits comment on an example opt-in approach that could be included in the final CAIR model rules. If opt-in provisions are included in final model rules, States would not be required to include them, and both States with and without opt-in provisions could participate in the EPA-managed cap-and-trade programs. States that chose to include opt-ins would be required to adopt EPA's methodology for including opt-ins as is.

Description of Potential Opt-In Approach

Opt-ins would be restricted to boilers and turbines that (1) exhaust to a stack or duct, and (2) meet the same monitoring and reporting requirements as CAIR-affected units. These requirements ensure the consistent, rigorous monitoring and reporting required to maintain the integrity of the emissions cap and trading market. To establish baseline emissions and operating information, opt-in units would be required to monitor and report in accordance with part 75 for a minimum of one full calendar year prior to the unit entering the CAIR trading program. If 3 or more consecutive calendar years of part 75 quality assured emissions and heat input data are available, then an average of the most recent 3 calendar years would be used to establish the baselines.

If a unit chooses to opt-in, the unit is required to opt into both the SO2 and NOX cap-and-trade programs. By requiring units to opt-in for both SO2 and NOX, opt-in units are encouraged to develop integrated control strategies. In addition, the burden of including opt-in units in the cap-and-trade programs could be somewhat offset by the benefit of both SO2 and NOX emission reductions.

Opt-in units would be allocated SO2 and NOX allowances on a year-by-year basis. The annual updating of allocations based upon utilization reduces concerns that individual opt-in units may shift utilization and, therefore, emissions, to other, unaffected units. Opt-in allocations would be based upon (1) an emission rate, and (2) the lesser of the baseline heat-input or the actual heat input measured at the unit for the prior year. For example, the potential SO2 allocation for an opt-in unit could be calculated by taking (i) the lesser of the unit's actual heat-input for the prior year or the unit's annual average baseline heat input for the most recent 3 years for which part 75 quality-assured data are available (or, if 3 years of such data are not available, the one year prior to opting into the CAIR programs) and multiplying it by (ii) the lesser of the unit's baseline SO2 emissions rate, the most stringent State or Federal SO2 emissions limitation that applies to the unit during the calender year prior to the year in which the unit is being allocated allowances, or the emission rate representing 50 percent of the unit's baseline SO2 emission rate (in lb/mmBtu)for the years 2010 through 2014 and 35 percent of the units's baseline SO2 emission rate (in lb/mmBtu) for 2015 and beyond. The EPA takes comment on this approach and specifically solicits comment on allocating to opt-in units at a range of 20 to 65 percent below their baseline SO2 emission rates—the equivalent of multiplying the baseline emission rate in the above equation by 80 to 35 percent of their baseline emissions, respectively. The NOX allocation for an opt-in unit could be calculated by taking (i) the lesser of the unit's actual heat-input for the prior year or the unit's annual average baseline heat input for the most recent 3 years for which part 75 quality assured data is available or, if 3 years of such data are not available, the one year prior to opting into the CAIR program and multiplying it by (ii) the lesser of the unit's baseline NOX emission rate, the most stringent State or Federal NOX emissions limitation that applies to the opt-in unit at any time during the calendar year prior to opting into the CAIR program, or 0.15 lb/mmBtu for the years 2010 through 2014, and 0.11 lb/mmBtu for the years 2015 and beyond (these rates are based on the average emission rates at which EPA projects EGUs will be emitting). The EPA is taking comment on this approach and specifically solicits comment on allocating to opt-in units at a range of levels that are 20 to 65 percent below their baseline NOX emissions, where an emissions rate of 0.11 lb NOX/mmBtu is roughly equivalent to a 65 percent reduction.

States would need to notify EPA after the end of the calendar year in order to allocate SO2 and NOX allowances to an opt-in unit for the next calendar year. Because opt-in allocations would be based upon data developed for the previous year, the allocations would be distributed a few months after the beginning of the next year (e.g., by April 1 of the next year, which would be of the year for which the allowances are needed for compliance).

Non-EGU boilers and turbines under the NOX SIP Call that choose to opt-in to the CAIR cap-and-trade programs would still be required to meet the NOX SIP Call seasonal NOX limitations. (The EPA does not have modeling, similar to that for EGUs, that projects that if non-EGUs meet the annual NOX emission limits, they will also meet the ozone season NOX emission limit as well.) This requirement would ensure that the NOX SIP Call States continue to meet their summertime NOX emission limits and make progress toward attaining the ozone NAAQS.

Opt-in units must remain in the CAIR program for at least 5 years. This would improve the cost effectiveness of implementing the program and would avoid potential incentives for opting in and out of the program. An opt-in unit could withdraw from the CAIR program any time with the request being effective on December 31 following the submission of the request or a subsequent December 31. The EPA believes that the administrative burden for a permitting authority in processing a withdrawal effective during a calendar year—particularly in ascertaining the disposition of SO2 and NOX allowances and in determining compliance for a partial calendar year—would be sufficient to warrant the prohibition of an effective date of withdrawal during a calendar year. Further, EPA believes that an opt-in unit should not be allowed to withdraw retroactively, whether during a calendar year or at the end of a prior calendar year. The ability to withdraw retroactively could reduce the incentive to comply since an opt-in unit could simply withdraw once it projects that it will not hold enough SO2Start Printed Page 32714and/or NOX allowances to account for its SO2 and/or NOX emissions for that calendar year. At best, under such a scenario, there would be no benefit from allowing the opt-in of the unit. Under an alternate scenario, allowing the unit to “opt out” of the program during a calendar year could result in higher overall SO2 and/or NOX emissions, since an opt-in unit could reduce its emissions during part of the year, sell some of its allowances, and increase its emissions after withdrawing from the program. Such increased emissions would not be accounted for with the requisite surrender of SO2 and/or NOX allowances required under the CAIR cap-and-trade programs and could occur outside of a State's annual budget for SO2 and/or NOX. The opt-in unit could, in effect, shift utilization from the part of the year for which it must surrender allowances for emissions to the part of the year for which emissions do not require an allowance surrender.

Opt-in permits would be terminated for any unit that becomes a CAIR-affected unit. This change in regulatory status for an opt-in unit could occur as a result of a modification or reconstruction that may take place at the unit. An opt-in unit that becomes a CAIR-affected unit would be required to notify the permitting authority within 30 days of the change in regulatory status. The permitting authority should revise the opt-in permit to reflect the CAIR permit content requirements of subparts CC and CCC (for NOX and SO2, respectively), effective as of the date of the change in status. The SO2 and NOX allowances would be deducted or allocated as necessary to ensure that the appropriate number of allowances are allocated to the unit consistent with the proposed CAIR trading rules for each calendar year after the effective date of the change in status.

4. Structure of Proposed CAIR Model Trading Rules

In order to make the proposed CAIR NOX and SO2 model trading rules as simple and consistent as possible, EPA designed them to parallel the model trading rules of the NOX SIP Call (part 96) and the Federal NOX Budget Trading Program (part 97). Because EPA is proposing new CAIR NOX and SO2 model rules—separate from the existing model rule in part 96—States can continue to reference part 96 as they implement the NOX SIP Call through 2009. The new CAIR NOX and SO2 model rules use the same basic structure as part 96 and will allow for an easier transition to the CAIR rules as States and sources will already be familiar with the rule layout. Specifically, the model rules will be codified as follows:

  • NOX SIP Call model cap-and-trade rule will remain in part 96 subparts A through J;
  • CAIR NOX model cap-and-trade rule will be created in part 96 subparts AA through HH;
  • CAIR SO2 model cap-and-trade rule will be created in part 96 subparts AAA through HHH; In addition, today's SNPR will add and reserve subparts between those proposed in today's action (i.e., subparts K through Z, subparts II through ZZ, and subparts III through ZZZ). Both the CAIR NOX and SO2 model rules will rely upon the detailed unit-level emissions monitoring and reporting procedures of part 75. (Note that proposed regulations establishing SIP requirements under the CAIR, i.e., part 51, are discussed in section III of today's action.) Additionally, section III of today's SNPR proposes revisions to part 72 through 77 in order to, among other things, harmonize the title IV Acid Rain Program's SO2 cap-and-trade provisions with those of the proposed CAIR.

B. Elements of the Proposed NOX and SO2 Model Trading Rules, Subparts AA Through HH and AAA Through HHH

This section of today's SNPR describes the purpose of each subpart of the proposed NOX and SO2 model trading rules in parallel. The descriptions highlight any improvements relative to corresponding sections in the existing part 96 (NOX SIP Call) and part 97 (Federal NOX Budget Trading Program) model rules. In addition, each subsection notes provisions that have been specifically adapted for either the CAIR SO2 or NOX trading program.

1. Subparts AA and AAA, CAIR NOX and SO2 Trading Program Applicability and General Provisions

a. 96.101 and 96.201 purpose. This section states the reason for the regulation.

b. 96.102 and 202 Definitions and 96.103 and 96.203 measurements, abbreviations, and acronyms. Many of the definitions, measurements, abbreviations, and acronyms remain unchanged from those used in 40 CFR parts 96 and 97, in order to maintain consistency among programs. However, certain terms that are specific to the CAIR SO2 and NOX model cap-and-trade rule have been added and certain other terms have been modified.

In today's supplemental proposal of the model SO2 cap-and-trade rule, EPA has defined CAIR SO2 allowances to reflect the SO2 retirement ratios described in section VIII.B.2.f (69 FR 6932) of the January 2004 proposal. Specifically, the definition established the number of title IV or CAIR SO2 allowances, by vintage, that must be retired to offset one ton of SO2 emissions. Specifically, one SO2 allowance of vintage years 2009 and earlier authorizes the emission of one ton of SO2. Two SO2 allowances of vintage years 2010-2014 authorize one ton of SO2 emission. Three SO2 allowances of vintage years 2015 and beyond authorizes the emission of one ton of SO2.

In today's SNPR, EPA is clarifying the definition of cogeneration unit included in the January 2004 proposal. (This clarification also corrects an error in the January 2004 proposal, where it was erroneously stated that the definition of a cogeneration facility under the title IV Acid Rain Program and the NOX SIP Call was based on the Federal Energy Regulatory Commission's qualifying cogeneration facility definition.) The EPA proposes to use a definition of cogeneration unit that is based on the Acid Rain Program definition of “cogeneration unit” and the Federal Energy Regulatory Commission's (FERC) definitions of “cogeneration unit” and “qualifying cogeneration facility.” The proposed “cogeneration unit” has two elements. First, in order to be a “cogeneration unit,” a unit must produce electric energy and useful thermal energy for industrial, commercial, heating or cooling purposes, through the sequential use of original fuel energy. See 40 CFR 72.2 and 18 CFR 292.202(c) (“cogeneration” definition). Second, the unit must meet the operating and efficiency standards under 18 CFR 292.205, but applied to all cogeneration units, instead of applying the efficiency standards only to oil- and gas-fired units as under 18 CFR 292.205. The EPA believes that applying the operating and efficiency standards to all units would be more consistent with its fuel-neutral approach throughout this proposed rule. In addition, not applying the efficiency standards to coal-fired units would be counter-productive to EPA's efforts to reduce SO2 and NOX emissions under this proposed rule because of the relatively high SO2 and NOX emissions from coal-fired units. Thus, under the second element of today's proposed “cogeneration unit” definition, a topping-cycle cogeneration unit must meet the following requirements.

The useful thermal energy output of the unit must be no less than 5 percent of the total energy output during the 12-month period beginning with the date the unit first produces electric energy Start Printed Page 32715and any subsequent calendar year. The useful power output of the unit plus one-half the useful thermal energy output, during the 12-month period beginning with the date the unit first produces electric energy, and any calendar year after the year in which the unit first produces electric energy, must be: (i) No less than 42.5 percent of the total energy input to the unit; or (ii) if the useful thermal energy output is less than 15 percent of the total energy output of the unit, no less than 45 percent of the total energy input to the unit.

For bottoming-cycle cogeneration units, the useful power output of the unit during the 12-month period beginning with the date the unit first produces electric energy, and any subsequent calendar, must be no less than 45 percent of the energy input.

c. 96.104 and 204 Applicability. Today's SNPR proposes to affect fossil fuel-fired boilers and turbines serving an electrical generator with a nameplate capacity exceeding 25MW and producing power for sale. Cogeneration units would be affected if they meet the definition in b. above.

d. 96.105 and 205 Retired unit exemption. This section of today's SNPR provides an exemption from the CAIR NOX and SO2 trading program requirements for retired units so that retired CAIR units will be free from unnecessary requirements (e.g., emissions monitoring and reporting). The EPA proposes an exemption beginning on the day the unit permanently retires, requiring no notice and comment period regarding the retirement. This provision proposes that the CAIR Designated Representative (CAIR DR) (i.e., the person authorized by the owners and operators to make submissions and handle other matters) submit notification to the permitting authority of the CAIR unit's retirement within 30 days of the cessation of activity. (Note that the CAIR DR designation is similar to the title IV Acid Rain Program's Designated Representative, or “Acid Rain DR,” and the NOX SIP Call's Authorized Account Representative, or “AAR.”) In response, the permitting authority would amend the operating permit in accordance with the exemption and notify EPA of the unit's status as exempt. This provision imposes conditions that all program requirements prior to the exemption are fulfilled and records are kept on site to verify the non-emitting status of the retired unit. A retired unit could continue to hold NOX and SO2 allowances previously allocated or be allocated NOX and SO2 allowances in the future depending on the allocation provisions adopted by the State where the retired unit is located. The number of future year NOX and SO2 allowances that a retired unit would be allocated would be dependent on the given State's allocation system. The NOX and SO2 allowance allocations are discussed in sections IV.A.3.a and IV.B.5 of this SNPR.

In order to resume operation without violating program requirements (i.e., an exemption requires that the unit's permit language be changed to reflect that it would not emit any NOX and SO2 emissions), the CAIR DR must submit a permit application to the permitting authority no less than 18 months (or less, if so specified by the applicable State permitting regulations) prior to the date on which the unit is to resume operation, to allow the permitting authority time to review and approve the application for the unit's re-entry into the program. If a retired unit resumes operation, EPA proposes to automatically terminate the exemption under this part.

e. 96.106 and 96.206 Standard requirements. Today's SNPR delineates the standard requirements that CAIR units and their owners, operators, and CAIR DRs must meet under the CAIR NOX and SO2 cap-and-trade program. This provision sets forth references to other portions of the cap-and-trade rule for the full range of program requirements: Permits, monitoring, NOX and SO2 emissions limitations, excess emissions, recordkeeping and reporting, liability, and effect on other authorities. For example, the permitting, monitoring, and emissions limit requirements are discussed in general and the relevant sections of the cap-and-trade rule are cited. The liability provisions state that the requirements of the trading program must be met, and any knowing violations or false statements are subject to enforcement under the applicable State or Federal law. Violations and the associated liability are established on a facility-wide basis. The provision addressing the effect on other authorities establishes that no provision of the trading program can be construed to exempt the owners or operators of a CAIR source from compliance with any other provision of the applicable SIP, any federally enforceable permit, or the CAA. This provision ensures, for example, that a State may set a binding source-specific NOX and SO2 limitation and, regardless of how many allowances a CAIR source holds under the trading program, the emissions limit established in the SIP cannot be violated.

Automatic penalties for non-compliance have been key to the success of the title IV and the NOX SIP Call's cap-and-trade programs and are an important feature of the proposed CAIR model rules as well. Simple, transparent, automatic penalties avoid litigation, which can be costly for both the air authorities and the sources, for most non-compliance instances. For severe non-compliance, the air authorities retain the right to pursue civil actions.

f. 96.107 and 207 Computation of time. This section clarifies how to determine the deadlines referenced in the proposal. For example, deadlines falling on a weekend or holiday are extended to the next business day. These are the same computation-of-time provisions as are in the regulation for the title IV and the NOX SIP Call emissions trading programs.

2. Subparts BB and BBB, CAIR Designated Representative for CAIR Sources

Sections 96.108 and 96.208 of today's SNPR establish procedures for appealing the decisions of the Administrator regarding the model cap-and-trade rules in part 78. Part 78 also includes administrative appeal procedures for the Acid Rain Program and the Federal NOX Budget Trading Program. Today's SNPR revises part 78 to make these procedures applicable to the CAIR NOX and SO2 trading programs as well.

Sections 96.110 through 96.114 and 96.210 and 96.214 of today's proposed CAIR NOX and SO2 cap-and-trade programs rule establish the process for certifying the CAIR DR and describe his or her duties. Patterned after the roles and responsibilities of the title IV Acid Rain Program's DR, a CAIR DR is the individual authorized to represent the owners and operators of each CAIR NOX and SO2 unit at a CAIR source (i.e., a facility that includes at least one CAIR affected unit) in matters pertaining to the CAIR cap-and-trade programs. Because the CAIR DR represents the owners and operators of all the CAIR NOX and SO2 units at a CAIR source, the CAIR DR must certify that he or she was selected by an agreement binding on all such owners and operators and is authorized to act on their behalf. The CAIR DR's responsibilities include: The submission of permit applications to the permitting authority, submission of monitoring plans and certification applications, holding and transferring CAIR allowances, and submission of emissions data. The rule proposes that each CAIR source have one DR that is responsible for both the NOX and SO2 cap-and-trade program requirements. Additionally, the rule proposes to Start Printed Page 32716require that the CAIR DR be the same individual as the title IV Acid Rain Program's Designated Representative (Acid Rain DR) at each source. These requirements will ensure that one individual is responsible for all matters pertaining to the CAIR as well as significantly reduce the burden on the data systems used in the administration of the cap-and-trade programs.

The EPA recognizes that the CAIR DR cannot always be available to perform his or her duties. Therefore, the rule proposes to allow for the appointment of one alternate CAIR DR for a CAIR source. The alternate CAIR DR would have the same authority and responsibilities as the CAIR DR. Therefore, unless expressly provided to the contrary, whenever the term “CAIR Designated Representative” is used in the rule, it should be read to apply to the alternate CAIR DR as well. While the alternate CAIR DR would have full authority to act on behalf of the CAIR DR, all correspondence from EPA, including reports, would be sent only to the CAIR DR. It should be noted that additional flexibility is provided within the electronic data systems that EPA uses to administer the program. Within these systems the CAIR DR may assign “agents” to perform specific tasks on his or her behalf, such as submission of allowance transfers and electronic data reports.

Today's SNPR requires the completion and submission of the Certificate of Representation in order to certify a CAIR DR for a CAIR source and all CAIR NOX and SO2 units at the source. There would be one standard form (the Certificate of Representation [DR form]) which would be submitted by sources to EPA. The DR form would include identifying information for the source, the CAIR DR and the alternate CAIR DR, if applicable; the name of every owner and operator of the source and each CAIR unit at the source; and certification language and signature of the CAIR DR and alternate, if applicable. The EPA would design this form to also include the Acid Rain DR certifications, and the CAIR DR would indicate which units at the source are included in which programs. This form can also be completed and submitted electronically. Upon receipt of a complete DR form, EPA would establish a compliance account for each source in the systems used to track SO2 and NOX allowances.

In order to change the CAIR DR, alternate CAIR DR, or list of owners and operators, EPA is proposing that a new complete account certificate of representation be submitted. The EPA believes the CAIR DR requirements afford the regulated community with flexibility, while ensuring source accountability and simplifying the administration of the cap-and-trade program.

3. Subparts CC and CCC, CAIR Permits

a. 96.120 and 96.220 General CAIR NOX and SO2 trading program permit requirements. The EPA has attempted to minimize the number of new procedural requirements for CAIR permitting and to defer, whenever possible, to the permitting programs already established by the permitting authority. The proposed CAIR trading program regulations assume that the CAIR permit would be a portion of a federally enforceable permit issued to the CAIR source and administered through permitting vehicles such as operating permits programs established under title V of the CAA and 40 CFR part 70. Generally, the permits regulations promulgated by the permitting authority cover: Permit application, permit application shield, permit duration, permit shield, permit issuance, permit revision and reopening, public participation, and State and EPA review. The proposed CAIR trading program permit regulations generally require use of the procedures under these other regulations and add some requirements such as CAIR permit application submission and renewal deadlines, CAIR permit application information requirements and permit content, and the term “CAIR permit”. The term “CAIR permit” throughout this preamble and the CAIR trading program regulations therefore refers to the CAIR trading program portion of the permit issued by the permitting authority to a CAIR source.

b. 96.121 and 96.221 Submission requirements for CAIR NOX and SO2 permit applications. The proposed rule sets the initial CAIR permit application deadlines for units in operation before January 1, 2007 so that the permits will be issued by January 1, 2010. January 1, 2010 is the beginning of the first control period for the CAIR cap-and-trade program, and therefore also the date by which initial CAIR permits for existing units should be effective. Application submission deadlines are based on the permitting authority's title V permitting regulations. For instance, if a permitting authority's permitting regulations allowed 12 months for final action by the permitting authority on a permit application, the application deadline would be the later of January 1, 2009 (12 months prior to January 1, 2010) or 12 months before the unit commences operation. The same principle applies to CAIR units commencing operation on or after January 1, 2007, except that the application submission deadline is the later of the date the CAIR unit commences operation or January 1, 2010. The CAIR permit renewal application deadlines are the same as those that apply to permit renewal applications in general for sources under Title V. For instance, if a permitting authority requires submission of a Title V permit renewal application by a date which is 12 months in advance of a title V permit's expiration, the same date would also apply to the CAIR permit application.

c. Sections 96.122 and 96.222, Information requirements for CAIR permit applications and §§ 96.123 and 96.223 CAIR permit contents and term. The CAIR cap-and-trade program requires that a CAIR permit application properly identify the source and include the standard requirements under proposed sections §§ 96.121 and 96.221. The CAIR cap-and-trade program permit application should include all elements of the program (including the standard requirements). Such an approach allows the permitting authority to incorporate virtually all of the applicable CAIR cap-and-trade program requirements into a CAIR permit by including as part of such permit the CAIR permit application submitted by the source. Directly incorporating the CAIR permit application into the CAIR permit and, thus, into the source's operating permit or the overarching permit minimizes the administrative burden on the permitting authority of including the CAIR cap-and-trade program applicable requirements. The permitting authority may revise the term of the CAIR permit as necessary to facilitate coordination of the renewal with the issuance, revision, or renewal of the sources title V permit.

d. Sections 96.124 and 96.224, CAIR permit revisions. For revisions to the CAIR permit, the CAIR trading program again defers to the regulations addressing permits revisions promulgated by the permitting authority under title V and 40 CFR part 70 or 71. The proposal also provides that the allocation, transfer, or deduction of allowances is automatically incorporated in the CAIR permit, and does not require a permit revision or reopening by the permitting authority. The CAIR permit must, however, expressly state that each source must hold enough allowances to account for emissions by the allowance transfer deadline for each control period. The EPA believes that requiring the permitting authority to revise or reopen a CAIR permit each time a CAIR allowance allocation, transfer, or deduction is made would be burdensome and unnecessary. Start Printed Page 32717

4. Subpart DD and DDD, CAIR Compliance Certification

Sections 96.130 through 96.131 and 96.230 through 96.231 are reserved. The NOX and SO2 cap-and-trade programs in today's SNPR do not include the requirement for the source to submit a compliance certification report. The requirements are unnecessary because these sources already certify compliance with the emissions monitoring and reporting requirements when they submit their quarterly emissions data. In addition, these sources will submit compliance certifications under title V for all CAA requirements, including the CAIR, NOX SIP Call, and Acid Rain trading programs.

5. Subpart EE and EEE, CAIR NOX and SO2 Allowance Allocations

Sections 96.140 through 96.142 of today's SNPR propose both required provisions (i.e., State-by-State NOX emissions budgets and the timing for States to report unit-by-unit NOX allocations) as well as the example allocation approach, provided as an illustration. Specifically, sections 96.140 and 96.240 propose the State-by-State NOX emission budgets that may be allocated by the State. Section 96.141 proposes elements of the NOX allocation systems that States are required to include (i.e., a 3 year minimum for advanced notification by the State of allocations and the annual timing of submitting to EPA the updated, unit-by-unit allocations) in order to ensure consistency for sources across all States participating in the EPA-managed cap-and-trade program. Section 96.142 proposes provisions that would implement the example approach for the NOX cap-and-trade program—discussed in detail in above, including procedures for creating a new unit set-aside and incorporating new units into a permanent allocation.

Sections 96.240 through 242, pertaining to the CAIR SO2 cap-and-trade program, are reserved. The title IV SO2 allowance allocation provisions of the CAA remain in effect. Should the final CAIR program make CAIR SO2 allowances available to the States, EPA would include requirements for a 3 year minimum for advanced notification for unit-by-unit allocations that would be similar to those proposed for NOX allocations in today's action.

6. Subpart FF and FFF, CAIR NOX and SO2 Allowance Tracking Systems.

a. Overview of tracking system. Sections 96.150 through 96.157 and 96.250 through 96.257 of today's proposed model rule cover the system to track CAIR NOX and SO2 allowances. The proposed rule is intended to make use of the allowance tracking systems developed for the NOX SIP Call and Acid Rain Program, with some modifications. Such an approach would help to allow the integration of the CAIR NOX and SO2 cap-and-trade programs with the existing cap-and-trade programs under the NOX SIP Call and Acid Rain Program. It would also save industry and government the time and resources necessary to develop new tracking systems.

The current automated systems will be used to track CAIR NOX and SO2 allowances held by CAIR sources under the CAIR NOX and SO2 cap-and-trade programs, as well as those allowances held by other organizations or individuals. Specifically, the systems would track the allocation of all CAIR NOX and SO2 allowances, holdings of CAIR NOX and SO2 allowances in accounts, deduction of CAIR NOX and SO2 allowances for compliance purposes, and transfers between accounts. The primary role of the tracking system is to provide an efficient, transparent, and automated means of monitoring compliance with the CAIR NOX and SO2 cap-and-trade programs. It would also provide the allowance market with a record of ownership of allowances, dates of allowance transfers, buyer and seller information, and the serial numbers of allowances transferred.

The EPA is proposing that the tracking system contain two primary types of accounts: Compliance accounts and general accounts. The EPA is proposing that compliance accounts for NOX and SO2 be created for each CAIR source with one or more CAIR units, upon receipt of the Certificate of Representation form. General accounts are created for any organization or individual upon receipt of a General Account Information form.

b. Establishment of accounts.

i. Compliance accounts. The EPA is proposing to require source-level accounts for compliance with the CAIR NOX and SO2 cap-and-trade programs. The EPA's experience in conducting compliance determinations (reconciliation) for the Acid Rain cap-and-trade program at strictly the unit level indicates that there is the potential for affected facilities to be subject to monetary penalties simply for having too few allowances in one unit account at a source when there are plenty of available allowances at another unit account at the same source. This amounts to a monetary penalty, potentially large, for an accounting error that has no significant environmental effect. In developing the compliance procedures for the NOX SIP Call cap-and-trade programs, this was taken into consideration and overdraft accounts were introduced to provide some flexibility in managing allowances at a source. However, both EPA and the regulated community find that, in practice, overdraft accounts and their use can be quite complicated and do not significantly reduce the burden of unit-level accounting. Therefore, EPA is proposing compliance accounts be established at the source level. This will significantly reduce the accounting burden for both EPA and the regulated community without causing any environmental consequences. The source-level accounts would be identified by a account number incorporating the source's Office of Regulatory Information System's (ORIS) code or facility identification number.

Today's SNPR also modifies the Acid Rain Program regulations to provide for source-level compliance. This will facilitate the interaction of the Acid Rain Program and the CAIR cap-and-trade programs.

ii. General accounts. Today's proposed model rules allow any person or group to open a general account. These accounts would be identified by the “9999” that would compose the first four digits of the account number. Unlike compliance accounts, general accounts cannot be used for compliance but can be used for holding or trading NOX or SO2 allowances (e.g., by allowance brokers or owners of multiple CAIR NOX or SO2 units or sources). General accounts are currently used for both SO2 allowances in the Acid Rain Program and NOX allowances in the NOX SIP Call cap-and-trade program.

To open a general account, a person or group must complete the standard General Account Information form, which is similar to the Certificate of Representation that precedes the opening of a compliance account. The form must include the name of a natural person who would serve as the NOX or SO2 Authorized Account Representative (AAR). The form would include identifying information for the AAR and alternate AAR (if applicable); the organization name and type, if applicable; the names of all parties with an ownership interest with the respect to the NOX or SO2 allowances in the account; and certification language and signatures of the NOX or SO2 AAR and alternate, if applicable.

Revisions to information regarding an existing general account are made by submitting a new General Account Information form which would be sent to EPA in all cases, whether the form is Start Printed Page 32718used to open a new account, or revise information on an existing one. The EPA would notify the NOX or SO2 AAR cited on the application of the establishment of his or her general account or of the registration of requested changes.

c. Recordation of allowance allocations. The NOX allocations for existing units for the first 5 years (2010-2014), as prescribed by each State, would be recorded into the CAIR NOX (source-level) compliance accounts prior to the first control period in 2010. Prior to the second control period, in 2011, and each year thereafter, NOX allocations for the new fifth sixth year, as prescribed by each State, would be recorded in each compliance account (e.g., in 2011, year 2016 NOX allowances would be allocated).

Title IV SO2 allowances are allocated and recorded under the Acid Rain Program so this section of the CAIR SO2 model cap-and-trade rules is reserved. Should the final CAIR rule make CAIR SO2 allowances available to States, requirements for the recordation of CAIR SO2 allowances would be similar to those proposed for NOX allocations in today's action.

d. Compliance. Once a control period has ended (i.e., December 31) CAIR NOX and SO2 sources would have a window of opportunity (i.e., until the allowance transfer deadline of midnight on March 1 following the control period) to evaluate their reported emissions and obtain any additional NOX or SO2 allowances they may need to cover the emissions during the year.

NOX: The compliance requirement would be to hold one NO x allowance for each ton of NOX emissions at each CAIR unit at the source. For each ton of NOX emissions for which the source does not hold an allowance, the excess emissions offset would be a deduction of 3 NOX allowances allocated for the year after the year in which the excess emissions occur.

SO2: The compliance requirement would depend upon the vintage of the SO2 allowance being submitted for compliance. For allowances with vintage years of 2009 and earlier, one SO2 allowance must be held for each ton of SO2 emissions. For allowances for vintage years 2010-2014, a source must hold 2 allowances of these vintages for each ton of SO2 emissions. A source must hold 3 SO2 allowances of vintage years 2015 and beyond for each ton of SO2 emissions at the source. For each ton of SO2 emissions for which the source does not hold the requisite number of SO2 allowances, the excess emissions offset would deduct three times the number of SO2 allowances required for the sources emissions for the vintage year immediately following the year in which the excess emissions occurred. This would result in six 2010-2014 vintage year allowances and nine 2015 and beyond year allowances, since two 2010-2014 allowances or three 2015 and beyond allowances authorize one ton of SO2 emissions.

The EPA believes that it is important to include this automatic offset deduction because it ensures that non-compliance with the NOX and SO2 emission limitations of this part is a more expensive option than controlling emissions. The EPA required an automatic deduction of 3-for-1 in the NOX SIP Call, and is taking comment on the ratios used in the proposed model rules. The automatic offset provisions do not limit the ability of the permitting authority or EPA to take enforcement action under State law or the CAA.

In the Acid Rain Program, one SO2 allowance must be held for each ton of SO2 emissions. As discussed above, one, two, or three SO2 allowances must be held for each ton of emissions, depending on the year for which the allowances were allocated. Consequently, non-compliance with the allowance-holding requirement in the CAIR SO2 cap-and-trade program would not necessarily mean non-compliance with the allowance-holding requirement in the Acid Rain Program. Therefore, it is necessary to ensure that compliance with the Acid Rain Program allowance-holding requirements is assessed independently from the CAIR requirements. The EPA is proposing a detailed allowance deduction order for each CAIR unit at each CAIR source where one allowance for each ton of emissions is deducted first (satisfying the Acid Rain requirement) and then the additional allowances are deducted to complete the CAIR SO2 requirement.

e. Banking. Banking is the retention of unused allowances from one control period for use in a later control period. Banking allows sources to create reductions beyond required levels and “bank” the unused allowances for use later. The EPA is proposing that banking of allowances after the start of the CAIR NOX and SO2 cap-and-trade programs be allowed with no restriction. Banking after a program starts and the budget is imposed allows sources to retain any allowances not surrendered for compliance at the end of each control period. Once the CAIR cap-and-trade program budgets are in place, sources may over-control for one or more years and withdraw from the bank in one or more later years. This type of banking provides the following advantages: Encourages early reductions, stimulates the market, and provides flexibility to sources, while also potentially causing NOX or SO2 emissions in some control periods to be greater than the allowances allocated for those years.

Allowing unrestricted banking is consistent with the current Acid Rain Program for SO2. The NOX SIP Call cap-and-trade program, however, has some restrictions on the use of banked allowances, a procedure called flow control. Flow control was first used in the OTC NOX cap-and-trade program and was carried over into the NOX SIP Call cap-and-trade program. The flow control provisions were designed to discourage extensive use of banked allowances in a particular ozone season. Flow control establishes a 2-to-1 discount ratio on the use of banked allowances above a certain level. The discount ratio applies after the total number of banked allowances from all sources exceeds 10 percent of the regionwide NOX emissions budget. Flow control is a very complicated procedure to explain, understand, and implement. The experience in the OTC cap-and-trade program illustrated that flow control can cause allowance market complexity and confusion for the regulated community by stratifying the allowance market by vintages (i.e., the year for which the allowances are allocated), making banked allowances less valuable, and potentially increasing the cost of compliance. In addition to these negative effects, it remains difficult to ascertain an environmental benefit. The EPA is proposing to not use flow control in order to keep compliance with the CAIR cap-and-trade programs as simple and easy as possible.

7. Subparts GG and GGG, CAIR NOX and SO2 Allowance Transfers

The EPA is proposing that once a NOX or SO2 DR or AAR is appointed and an account is established, NOX or SO2 allowances can be transferred to or from the accounts with the submission of allowance transfer information, either on-line or through the use of an Allowance Transfer form. Transfers can occur between any accounts at any time of year with one exception: Transfers of current and past year allowances into and out of compliance accounts are prohibited after the allowance transfer deadline (March 1 following each control period) until EPA completes the annual reconciliation process by deducting the necessary allowances.

For those electing not to transfer allowances on-line, there would be one standard NOX and one standard SO2 Allowance Transfer form. This form would be submitted to the EPA in all Start Printed Page 32719cases. The form would generally include: the transferor and transferee allowance account numbers; the transferor's printed name, phone number, signature, and date of signature; and a list of allowances to be transferred, by serial number.

8. Subparts HH and HHH, CAIR NOX and SO2 Monitoring and Reporting

Clear, rigorous, and transparent monitoring and reporting of all emissions are the basis for holding sources accountable for their emissions and are essential to the success of any cap-and-trade program. Consistent and accurate measurement of emissions ensures that each allowance actually represents one ton of emissions and that one ton of reported emissions from one source is equivalent to one ton of reported emissions from another source. Similarly, such measurement of emissions ensures that each single allowance (or group of SO2 allowances, depending upon the SO2 allowance vintage) represents one ton of emissions, regardless of the source for which it is measured and reported. This establishes the integrity of each allowance, which instills confidence in the underlying market mechanisms that are central to providing sources with flexibility in achieving compliance. Given the variability in the type, operation, and fuel mix of sources in the proposed CAIR NOX and SO2 cap-and-trade programs, EPA believes that emissions must be monitored continuously in order to ensure the precision, reliability, accuracy, and timeliness of emissions data that support a cap-and-trade program. As proposed, part 96 subpart HH for NOX and subpart HHH for SO2 establish monitoring and reporting requirements for CAIR sources. These subparts reference the relevant sections of part 75 where the specific procedures and requirements for measuring and reporting NOX and SO2 mass emissions are found. These subparts are modeled after subpart H of part 96.

Part 75 was originally developed for the Acid Rain Program. The Acid Rain Program, as established by Congress in the 1990 Amendments to the Act, requires the use of continuous emissions monitoring systems (CEMS) or an alternative monitoring system that is demonstrated to provide information with the same precision, reliability, accuracy, and timeliness as a CEMS. The EPA believes that the use of CEMS is a critical part of ensuring the effectiveness of regional cap-and-trade programs. In implementing the Acid Rain Program, as well as the NOX SIP Call Trading Program, EPA has allowed alternatives to CEMS only where the total of the emissions contributed by specified categories of affected sources is de minimis in comparison to the emissions cap for the program, or where an alternative monitoring system has been demonstrated, according to specified criteria, to meet the standard Congress set. Provisions for monitoring and reporting NOX mass emissions were added to Acid Rain Program methodologies for both the OTC NOX Budget Program and for the NOX SIP Call. As a result, several alternative monitoring methodologies exist for qualifying sources to use. For example, there is a SO2 emissions data protocol that allows gas- or oil-fired units to use fuel sampling techniques along with fuel flow metering to quantify emissions. (See part 75, appendix D.) There is also a NOX estimation methodology for certain infrequently used gas- or oil-fired units that can be found in part 75, appendix E. There are also optional emissions calculation procedures for gas-or oil-fired sources emitting no more than 25 tons of SO2 annually or less than 100 tons of NOX annually which allow the use of conservative emission factors to estimate emissions. (See § 75.19.) All of the existing part 75 monitoring methodologies will be available to CAIR sources as applicable.

Sources subject to the CAIR must monitor and report NOX and SO2 mass emissions year round. The majority of CAIR sources are measuring and reporting SO2 mass emissions year round under the Acid Rain Program. Therefore, these sources will have little or no changes to make to their monitoring and reporting efforts under the CAIR. Most CAIR sources are also reporting NOX mass emissions year round under the NOX SIP Call. The CAIR-affected Acid Rain sources that are located in States that are not affected by the NOX SIP Call currently measure and report NOX emission rates year round, but do not currently report NOX mass emissions. These sources will need to modify only their reporting practices in order to comply with the proposed CAIR monitoring and reporting requirements. Today's SNPR is designed to be as consistent as possible with existing requirements in order to minimize the impact on CAIR sources of the monitoring and reporting requirements, while maintaining the integrity of the cap-and-trade programs.

The requirement to monitor and the associated monitoring deadlines are found in § 96.170 for NOX and § 96.270 for SO2 for the CAIR trading programs and require continuous measurement of SO2 and NOX emissions by all existing affected sources by January 1, 2009 using part 75 certified monitoring methodologies. New sources have separate deadlines based upon the date of commencement of operation, consistent with the Acid Rain Program.

The quality assurance (QA) requirements for the Acid Rain Program that were mandated by Congress under the CAA have been codified in appendices A and B of part 75. Part 75 specifies that each CEMS must undergo rigorous initial certification testing and periodic quality assurance testing thereafter, including the use of relative accuracy test audits (RATAs) and daily calibrations. A standard set of data validation rules apply to all of the monitoring methodologies. These stringent requirements result in an accurate accounting of the mass emissions from each affected source and provide prompt feedback if the monitoring system is not operating properly. In addition, when the CEMS is not operating properly, standard substitute data procedures are applied and result in a conservative estimate of emissions for the period involved. This ensures a level playing field among the regulated sources with consistent accounting for every ton of emissions and also provides an incentive to keep the monitoring system properly up to date with QA requirements. The NOX SIP Call trading program also requires part 75 QA procedures. The EPA proposes to require the same QA procedures (as applied to an entire year, not just the ozone season) for the CAIR program. Initial certification or recertification is required as specified in §§ 96.171 and 96.271. Recognizing that many of the CAIR units are already monitoring NOX or SO2 (sometimes both) under part 75 through existing programs, subparts HH and HHH allow continued use of previously certified CEMS when appropriate rather than automatically requiring recertification. Requirements for reporting data when the monitors do not meet QA specifications are found in §§ 96.172 and 96.272.

Sections 96.174 and 96.274 specify reporting requirements, which include general requirements, monitoring plan reporting, certification applications, quarterly emissions and operations reports, and compliance certifications. The EPA proposes to require year-round reporting of emissions and monitoring data from each affected unit. As required for the Acid Rain Program and the NOX SIP Call trading programs, quarterly emissions reports must be submitted to EPA electronically on a quarterly basis and in a format specified by the Agency using EPA-provided software. Many affected sources are Start Printed Page 32720already reporting some or all of this data to EPA under either the Acid Rain Program or the NOX SIP Call trading program and can continue to report that data along with any additional data that may be required by this program. The EPA has found centralized reporting to be necessary to ensure consistent review, checking, and posting of the emissions and monitoring data for all affected sources, which contributes to the integrity, efficiency, and transparency of the trading program. Another important feature is that sources regulated under the Acid Rain Program, NOX SIP Call, or the CAIR NOX and SO2 cap-and-trade programs must use the same reporting format and submit only one report with all of the information required for all of the applicable programs. Thus, if the same data is needed for multiple programs, the source needs to report it only once in the form of one comprehensive report.

Consistent with the current monitoring and reporting requirements in part 75 for the Acid Rain and the NOX SIP Call programs, the proposed rule would allow sources, § 96.175 of subpart HH of part 96 and under § 96.275 of subpart HHH of part 96, to petition for an alternative to any of the specified monitoring requirements in the rule. These provisions provide sources with the flexibility to petition to use an alternative monitoring system under subpart E of part 75 or variations of the standard monitoring requirements as long as the requirements of existing § 75.66 are met.

Sections 96.176 and 96.276 require heat input data to be measured and reported regardless of the type of monitoring system.

V. Clarifications to January 30, 2004 Proposal

This section provides clarifications to the January 2004 proposal where the preamble language provided in the published proposal was unclear, incomplete, inadvertently omitted, or inadvertently incorrect. Unless otherwise indicated, all references to the Federal Register69 FR 4566-4650—are to the proposed Interstate Air Quality Rule.

A. Scope of the Proposed Action

On 69 FR 4633 column 1, EPA discussed the NOX cap-and-trade program. Under the heading “States Outside the Proposed Region with Existing Regional NOX Cap-and-trade Programs”, EPA mistakenly identified Massachusetts in the list of States that participate in existing NOX trading markets that would not be affected by the proposed rules. Massachusetts should be deleted from that list because it would be affected by the proposed rules.

In the January 2004 proposal, we discussed regional control requirements and budgets based on a showing of “significant contribution” by upwind States to nonattainment in other States. (69 FR 4611-4613). CAA section 110(a)(2)(D), which provides the authority for the proposal, states among other things that SIPs must contain adequate provisions prohibiting, consistent with the CAA, sources or other types of emissions activity within a State from emitting pollutants in amounts that will “contribute significantly to nonattainment in, or interfere with maintenance by, any other State with respect to” the NAAQS.

Thus, CAA section 110(a)(2)(D) requires that States prohibit emissions that contribute significantly to downwind nonattainment. In the January 2004 proposal, we discussed both the air quality component and the cost-effectiveness component of the “contribute significantly” determination. The EPA has interpreted CAA section 110(a)(2)(D) to require that States reduce emissions by specified amounts, and has based those amounts on the availability of highly cost-effective controls for certain source categories. Following this interpretation, EPA based the January 2004 proposal on the availability of highly cost-effective reductions of SO2 and NOX from EGUs in States that meet EPA's proposed inclusion criteria.

We noted in the January 2004 proposal, with respect to the cost-effectiveness component, that one factor we consider in determining cost effectiveness is the identification of source categories which emit relatively large amounts of the relevant emissions. We noted that this element is particularly important in a case such as the proposed CAIR where the Federal government is proposing a multi-State regional approach to reducing transported pollution. (69 FR 4611).

One approach cited in the January 2004 proposal for ensuring that both the air quality component and the cost effectiveness component of the section 110 “contribute significantly” determination is met, is to consider a source category's contribution to ambient concentrations above the attainment level in all nonattainment areas in affected downwind States. Some have recommended a further refinement of this concept, suggesting that a source category should be included only if the proposed level of additional control of that category would meet a specified threshold. Under this suggested approach, EPA could determine, for example, that inclusion of a source category in a broad multi-State SIP call would be appropriate only if it would result in at least 0.5 percent of U.S. counties and/or parishes in the lower 48 States coming into attainment with a NAAQS. Given the number of counties and parishes in the United States, this requirement would be met if at least 16 counties in the lower 48 States were brought into attainment with a NAAQS as a result of the proposed level of control on a particular source category. Choice of a factor as low as 0.5 percent of U.S. counties and/or parishes reflects the fact, according to this approach, that, for every NAAQS, the vast majority of counties are already in attainment. Nevertheless, for most criteria pollutants, this figure represents a significant portion of the remaining nonattainment problem.

The EPA seeks comment on whether this test should be incorporated as a part of the “highly cost-effective” component of the “contribute significantly” requirement of CAA section 110(a)(2)(D) when a multi-State call for SIP revisions to address interstate transport of air pollution is at issue. The EPA has conducted air quality modeling of the January 2004 proposal which indicates that the proposed emissions reductions will bring 34 additional areas (from a base of 73 down to 39) into attainment with either the PM2.5 or 8-hour ozone NAAQS by 2015. Since there are over 3,000 counties and parishes in the lower 48 States, basing the highly cost-effective control levels in the proposed CAIR on EGUs would meet this 0.5 percent criterion.

States retain authority to decide which sources to control to achieve the required amounts of reductions, but EPA considers the costs of controls for more sources in determining what is a significant contribution. Other CAA mechanisms, such as SIP disapproval authority and State petitions under CAA section 126, are available to address more isolated instances of the interstate transport of pollutants.

B. Summary of Control Costs

The control cost summary provided on 69 FR 4632 column 2 indicates a marginal cost per ton of SO2 emissions of $805 in the first phase, and $989 in the second phase, of the proposed control program. These amounts were based on modeling performed to evaluate the implications of using retirement ratios to implement the emission reduction requirements of the Start Printed Page 32721rule. This modeling is different from the modeling used to evaluate highly cost-effective controls. The latter modeling is summarized in Table VI-1 on 69 FR 4613, and shows marginal costs of $700 per ton in the first phase, and $1000 per ton in the second phase.

C. Source of Cost Information

On 69 FR 4614, Table VI-4, EPA failed to include an additional footnote referencing the source of the cost information for the last entry in the table, “Revision of NSPS for New EGUs.” The footnote should have indicated that the cost information is derived from “Proposed Revision of Standards of Performance for Nitrogen Oxide Emissions from New Fossil-Fuel Fired Steam Generating Units: Proposed Revisions to Reporting Requirements for Standards of Performance for New Fossil-Fuel Fired Steam Generating Units,” 62 FR 36951. The control costs for SCR shown in the table are for coal-fired utility steam generating units and coal-fired industrial steam generating units. The proposed NSPS revision included ranges of costs; EPA presented the mid-point from those ranges in the table.

D. Judicial Review Under Clean Air Act Section 307

The EPA did not discuss in the January 2004 proposal the applicable provisions for judicial review of CAA section 307. Section 307(b)(1) indicates in which Federal Courts of Appeal petitions of review of final actions by EPA must be filed. This section provides, in part, that petitions for review must be filed in the Court of Appeals for the District of Columbia Circuit if (i) the agency action consists of “nationally applicable regulations promulgated, or final action taken, by the Administrator,” or (ii) the agency action is locally or regionally applicable, but “such action is based on a determination of nationwide scope or effect and * * * in taking such action the Administrator finds and publishes that such action is based on such a determination.”

Any final action related to the CAIR is “nationally applicable” within the meaning of section 307(b)(1). As an initial matter, through this rule, EPA interprets section 110(a)(2)(D)(i) of the CAA in a way that could affect future actions regulating the transport of pollutants. In addition the January 2004 proposal would require 29 States and the District of Columbia to decrease emissions of either SO2 or NOX, or both. The Interstate Air Quality Rule is based on a common core of factual findings and analyses concerning the transport of ozone, PM2.5 and their precursors between the different States subject to the Interstate Air Quality Rule. Finally, EPA has established uniform approvability criteria that would be applied to all States subject to the Interstate Air Quality Rule. For these reasons, the Administrator also is determining that any final action regarding the Interstate Air Quality Rule is of nationwide scope and effect for purposes of section 307(b)(1). Thus, any petitions for review of final actions regarding the Interstate Air Quality Rule must be filed in the Court of Appeals for the District of Columbia Circuit within 60 days from the date final action is published in the Federal Register.

VI. Statutory and Executive Order Reviews

This section of the SNPR discusses reviews conducted to meet the requirements of applicable statutes and executive orders. In the January 2004 proposal (69 FR 4566, January 30, 2004), EPA addressed the regulatory requirements that trigger statutory and executive order reviews. This supplemental proposal does not add substantive regulatory requirements. Rather, in general, it proposes a legal determination that implementation of the model rule will meet the better-than-BART requirements, clarifies aspects of the January 2004 proposal, and adds regulatory text for the proposals in the January 2004 proposal. Therefore, this supplemental proposal does not alter the findings of the January 2004 proposal.

The EPA provides additional information below relating to the National Technology Transfer and Advancement Act. In addition, the EPA plans to conduct additional analyses as discussed in the January 2004 proposal relating to the Paperwork Reduction Act (PRA), the Regulatory Flexibility Act (5 U.S.C. 601 et seq.) (RFA), as amended by the Small Business Regulatory Enforcement Fairness Act (Pub. L. 104-121) (SBREFA), and the Unfunded Mandates Reform Act of 1995 (Pub. L. 104-4) (UMRA) in the Notice of Final Rulemaking for this action. The EPA believes the analyses relating to the RFA and UMRA are not required for this rule by statute, but these analyses will be conducted for informational purposes. While it doesn't alter EPA's findings, EPA has performed additional analysis of the impact that the proposed CAIR may have on States not affected by the proposed CAIR. This analysis is available in the docket.

National Technology Transfer Advancement Act. Section 12(d) of the National Technology Transfer and Advancement Act (NTTAA) of 1995 (Pub. L. 104-113; 15 U.S.C. 272 note) directs EPA to use voluntary consensus standards in their regulatory and procurement activities unless to do so would be inconsistent with applicable law or otherwise impractical. Voluntary consensus standards are technical standards (e.g., materials specifications, test methods, sampling procedures, business practices) developed or adopted by one or more voluntary consensus bodies. The NTTAA directs EPA to provide Congress, through annual reports to OMB, with explanations when an agency does not use available and applicable voluntary consensus standards.

This SNPR would require all sources that participate in the trading program under proposed part 96 to meet the applicable monitoring requirements of part 75. Part 75 already incorporates a number of voluntary consensus standards. Consistent with the Agency's Performance Based Measurement System (PBMS), part 75 sets forth performance criteria that allow the use of alternative methods to the ones set forth in part 75. The PBMS approach is intended to be more flexible and cost effective for the regulated community; it is also intended to encourage innovation in analytical technology and improved data quality. At this time, EPA is not proposing any revisions to part 75, however EPA periodically revises the test procedures set forth in part 75. When EPA revises the test procedures set forth in part 75 in the future, EPA will address the use of any new voluntary consensus standards that are equivalent. Currently, even if a test procedure is not set forth in part 75, EPA is not precluding the use of any method, whether it constitutes a voluntary consensus standard or not, as long as it meets the performance criteria specified. However, any alternative methods must be approved through the petition process under § 75.66 before they are used under part 75. We welcome comments on this aspect of the proposed rulemaking and, specifically, invite the public to identify potentially applicable voluntary consensus standards and to explain why EPA should use such standards in this regulation.

VII. Proposed Rule Text

This SNPR includes the proposed rule text for the CFR for the basic elements of the CAIR proposal. This rule text includes the requirements for the affected jurisdictions to submit transport SIPs under the PM2.5 standard, the 8-hour ozone standard, or both; as well as for implementation of the Start Printed Page 32722applicable SO2 and NOX emissions budgets. It also includes model rule language that States may adopt for interstate trading rules. The rule language is located at the end of the preamble.

Specifically, EPA is today proposing to amend or revise the following rule text:

(i) Part 51 subpart A, §§ 51.1 through 51.45;

(ii) Part 51 subpart G, §§ 51.122 through 51.125;

(iii) Part 51, § 51.308;

(iv) Part 72, § 72.2;

(v) Part 73, various §§ 73.1 through 73.70;

(vi) Part 74, various §§ 74.18 through 74.50;

(vii) Part 77, various §§ 77.3 through 77.6;

(viii) Part 78, §§ 78.1, 78.3, 78.4 and 78.12;

(ix) Part 96, §§ 96.101 through 96.186 (NOX trading) and §§ 96.201 through 96.286 (SO2 trading).

Start List of Subjects

List of Subjects

, 73, 74, 77 and 78

End List of Subjects Start Signature

Dated: May 18, 2004.

Michael O. Leavitt,

Administrator.

End Signature

Title 40, chapter I, of the Code of Federal Regulations is proposed to be amended as follows:

Start Part

PART 51—[AMENDED]

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

Start Authority

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

End Authority

2. Part 51 subpart A is revised to read as follows:

Subpart A—Emission Inventory Reporting Requirements General Information for Inventory Preparers
51.1
Who is responsible for actions described in this subpart?
51.5
What tools are available to help prepare and report emissions data?
51.10
How does my State report emissions that are required by the NOX SIP Call and the Clean Air Interstate Rule?
Specific Reporting Requirements
51.15
What data does my State need to report to EPA?
51.20
What are the emission thresholds that separate point and non-point sources?
51.25
What geographic area must my State's inventory cover?
51.30
When does my State report which emissions data to EPA?
51.35
How can my State equalize the emissions inventory effort from year-to-year?
51.40
In what form and format should my State report the data to EPA?
51.45
Where should my State report the data?
End Part

Appendix A to Subpart A of Part 51—Tables and Definitions

Appendix B to Subpart A of Part 51—[Reserved]

Subpart A—Emission Inventory Reporting Requirements

General Information for Inventory Preparers

Who is responsible for actions described in this subpart?

States must inventory emission sources located on non-tribal lands and report this information to EPA.

What tools are available to help prepare and report emissions data?

We urge your State to use estimation procedures described in documents from the Emission Inventory Improvement Program (EIIP). These procedures are standardized and ranked according to relative uncertainty for each emission estimating technique. Using this guidance will enable others to use your State's data and evaluate its quality and consistency with other data.

How does my State report emissions that are required by the NOX SIP Call and the Clean Air Interstate Rule ?

The District of Columbia and States that are subject to the NOX SIP Call (§ 51.121) are subject to the emission reporting provisions of § 51.122. The District of Columbia and States that are subject to the Clean Air Interstate Rule are subject to the emission reporting provisions of § 51.125. This subpart A incorporates the pollutants, source, time periods, and required data elements for both of these reporting requirements.

Specific Reporting Requirements

What data does my State need to report to EPA?

(a) Pollutants. Report actual emissions of the following (see Definitions in appendix A to this subpart for precise definitions as required):

(1) Required pollutants for triennial reports of annual (12-month) emissions for all sources and every-year reports of annual emissions from Type A sources:

(i) Sulfur dioxide (SO2).

(ii) Volatile organic compounds (VOC).

(iii) Nitrogen oxides (NOX).

(iv) Carbon monoxide (CO).

(v) Lead and lead compounds.

(vi) Primary PM2.5. Emissions of filterable, condensible, and total PM2.5. should be reported, if all are applicable to the source type.

(vii) Primary PM10. Emissions of filterable, condensible, and total PM10 should be reported, if all are applicable to the source type.

(viii) Ammonia (NH3).

(2) Required pollutants for every-year reporting of annual (12-month) emissions for sources controlled to meet the requirements of § 51.123: NOX.

(3) Required pollutants for every-year reporting of annual (12-month) emissions of sources controlled to meet the requirements of 51.124: SO2.

(4) Required pollutants for all reports of ozone season (5 months) emissions: NOX.

(5) Required pollutants for triennial reports of summer daily emissions:

(i) NOX.

(ii) VOC.

(6) Required pollutants for every-year reports of summer daily emissions: NOX.

(7) A State may at its option include in its emissions inventory reports estimates of emissions for additional pollutants such as other pollutants listed in paragraph (a)(1) or hazardous air pollutants.

(b) Sources. Emissions should be reported from the following sources in all parts of the State, excluding sources located on tribal lands:

(1) Point.

(2) Non-point.

(3) Onroad mobile.

(4) Nonroad mobile.

(c) Supporting information. You must report the data elements in Tables 2a through 2d of appendix A to this subpart. You must also report information on the method of determination for data elements EPA may designate for such reporting in each reporting period. Additional information not listed in Tables 2a through 2d may be required, for Start Printed Page 32723example information identifying the State contact person for the submittal. We may ask you for other data on a voluntary basis to meet special purposes.

(d) Confidential data. We do not consider the data in Tables 2a through 2d of appendix A to this subpart confidential, but some States limit release of this type of data. Any data that you submit to EPA under this rule will be considered in the public domain and cannot be treated as confidential. If Federal and State requirements are inconsistent, consult your EPA Regional Office for a final reconciliation.

(e) Option to Submit Inputs to Emission Inventory Estimation Models in Lieu of Emission Estimates. For a given reporting year, EPA may allow States to submit comprehensive input values for models capable of estimating emissions from a certain source type on a national scale, in lieu of submitting the emission estimates otherwise required by this subpart.

What are the emission thresholds that separate point and non-point sources?

(a) All anthropogenic stationary sources must be included in your inventory as either point or non-point sources, except that biogenic emissions are not required to be reported.

(b) Sources which are major sources under section 302 or part D of title I of the Clean Air Act, considering emissions only of the pollutants listed in § 51.15(a), must be reported as point sources, starting with the 2008 inventory year. Provisions of part 70 affecting the definition of a major source apply to this subpart also. All pollutants specified in § 51.15(a) must be reported for point sources, not just the pollutant(s) which qualify the source as a point source. Prior to the 2008 inventory year, States may omit from point source treatment any source that would not be major if its actual emissions were considered rather than its potential to emit.

(c) If your State has lower emission reporting thresholds for point sources than paragraph (b) of this section, then you may use these in reporting your emissions to EPA.

(d) All stationary sources that are not subject to reporting as point sources must be reported as non-point sources. This includes wild fires and prescribed fires. Episodic wind-generated particulate matter emissions from sources that are not major sources may be excluded, for example dust lifted by high winds from natural or tilled soil. Emissions of non-point sources may be aggregated to the county level, but must be separated and identified by source classification code (SCC). Non-point source categories or emission events reasonably estimated by the State to represent a de minimis percentage of total county and State emissions of a given pollutant may be omitted.

What geographic area must my State's inventory cover?

Because of the regional nature of these pollutants, your State's inventory must be statewide, regardless of any area's attainment status.

When does my State report which emissions data to EPA?

All States are required to report two basic types of emission inventories to EPA: Every-year Cycle Inventory; and Three-year Cycle Inventory. The sources and pollutant to be reported vary among States.

(a) Every-year cycle. See Tables 2a, 2b, and 2c of appendix A to this subpart for the specific data elements to report every year.

(1) All States are required to report every year the annual (12-month) emissions of all pollutants listed in § 51.15(a)(1) from Type A (large) point sources, as defined in Table 1. The first every-year cycle inventory will be for the year 2003 and must be submitted to EPA within 17 months, i.e., by June 1, 2005. Subsequent every-year cycle inventories will be due 17 months following the end of the reporting year.

(2) States subject to §§ 51.123 and 51.125 of this subpart are required to report every year the annual (12-month) emissions of NOX from any point, non-point, onroad mobile, or nonroad mobile source for which the State specified control measures in its SIP submission under § 51.123 of this subpart. This requirement begins with the 2009 inventory year. This requirement does not apply to any State subject to § 51.123 solely because of its contribution to ozone nonattainment in another State.

(3) States subject to §§ 51.124 and 51.125 of this subpart are required to report every year the annual (12-month) emissions of SO2 from any point, non-point, onroad mobile, or nonroad mobile source for which the State specified control measures in its SIP submission under § 51.124 of this subpart. This requirement begins with the 2009 inventory year.

(4) States subject to §§ 51.123 and 51.125 are required to report every year the ozone season emissions of NOX and summer daily emissions of NOX from any point, non-point, onroad mobile, or nonroad mobile source for which the State specified control measures in its SIP submission under § 51.123 of this subpart. This requirement begins with the 2009 inventory year. This requirement does not apply to any State subject to § 51.123 solely because of its contribution to PM2.5 nonattainment in another State.

(5) States subject to the emission reporting requirements of § 51.122 are required to report every year the ozone season emissions of NOX and summer daily emissions of NOX from any point, non-point, onroad mobile, or nonroad mobile source for which the State specified control measures in its SIP submission under § 51.121(g) of this subpart. This requirement begins with the inventory year prior to the year in which compliance with the NOX SIP Call requirements is first required.

(6) If sources report SO2 and NOX emissions data to EPA in a given year pursuant to a trading program approved under § 51.123(o) or § 51.124(o) of this part or pursuant to the monitoring and reporting requirements of subpart H of 40 CFR 75, then the State need not provide annual reporting of the pollutants to EPA for such sources. If SO2 and NOX are the only pollutants required to be reported for the source for the given calendar year and emissions period (annual, ozone season, or summer day), all data elements for the source may be omitted from the State's emissions report for that period. We will make both the raw data submitted by sources to the trading programs and summary data available to any State that chooses this option.

(7) In years which are reporting years under the 3-year cycle, the reporting required by the 3-year cycle satisfies the requirements of this paragraph.

(b) Three-year cycle. See Tables 2a, 2b and 2c of appendix A to this subpart for the specific data elements that must be reported triennially.

(1) All States are required to report for every third year the annual (12-month) emissions of all pollutants listed in § 51.15(a)(1) from all point sources, non-point sources, onroad mobile sources, and nonroad mobile sources. The first 3-year cycle inventory will be for the year 2005 and must be submitted to us within 17 months, i.e., by June 1, 2007. Subsequent 3-year cycle inventories will be due 17 months following the end of the reporting year.

(2) States subject to § 51.122 must report ozone season emissions and summer daily emissions of NOX from all point sources, non-point sources, onroad mobile sources, and nonroad mobile sources. The first 3-year cycle inventory will be for the year 2005 and must be submitted to us within 17 months, i.e., by June 1, 2007. For States with a NOX SIP Call compliance date of Start Printed Page 327242007, the first 3-year cycle inventory will be for 2008. Subsequent 3-year cycle inventories will be due 17 months following the end of the reporting year.

(3) States subject to §§ 51.123 and 51.125 must report ozone season emissions of NOX and summer daily emissions of VOC and NOX from all point sources, non-point sources, onroad mobile sources, and nonroad mobile sources. The first 3-year cycle inventory will be for the year 2008 and must be submitted to us within 17 months, i.e., by June 1, 2010. Subsequent 3-year cycle inventories will be due 17 months following the end of the reporting year. This requirement does not apply to any State subject to § 51.123 solely because of its contribution to PM2.5 nonattainment in another State.

(4) Any State with an area for which EPA has made an 8-hour ozone nonattainment designation finding (regardless of whether that finding has reached its effective date) must report summer daily emissions of VOC and NOX from all point sources, non-point sources, onroad mobile sources, and nonroad mobile sources. The first 3-year cycle inventory will be for the year 2005 and must be submitted to us within 17 months, i.e., by June 1, 2007. Subsequent 3-year cycle inventories will be due 17 months following the end of the reporting year.

How can my State equalize the emissions inventory effort from year to year?

(a) Compiling a 3-year cycle inventory means much more effort every 3 years. As an option, your State may ease this workload spike by using the following approach:

(1) Each year, collect and report data for all Type A (large) point sources (This is required for all Type A point sources).

(2) Each year, collect data for one-third of your smaller point sources. Collect data for a different third of these sources each year so that data has been collected for all of the smaller point sources by the end of each 3-year cycle. You must save 3 years of data and then report all of the smaller point sources on the 3-year cycle due date.

(3) Each year, collect data for one-third of the area, nonroad mobile, and onroad mobile sources. You must save 3 years of data and then report all of these data on the 3-year cycle due date.

(b) For the sources described in paragraph (a) of this section, your State will therefore have data from 3 successive years at any given time, rather than from the single year in which it is compiled.

(c) If your State chooses the method of inventorying one-third of your smaller point sources and 3-year cycle area, nonroad mobile, onroad mobile sources each year, your State must compile each year of the 3-year period identically. For example, if a process hasn't changed for a source category or individual plant, your State must use the same emission factors to calculate emissions for each year of the 3-year period. If your State has revised emission factors during the 3 years for a process that hasn't changed, resubmit previous year's data using the revised factor. If your State uses models to estimate emissions, you must make sure that the model is the same for all three years.

(d) If your State needs a new reference year emission inventory for a selected pollutant, your State can not use these optional reporting frequencies for the new reference year.

(e) If your State is a NOX SIP Call State, you can not use these optional reporting frequencies for NOX SIP Call reporting.

In what form and format should my State report the data to EPA?

You must report your emission inventory data to us in electronic form. We support specific electronic data reporting formats and you are required to report your data in a format consistent with these. The term format encompasses the definition of one or more specific data fields for each of the data elements listed in Tables 2a, 2b, and 2c; allowed code values for categorical data fields; transmittal information; and data table relational structure. Because electronic reporting technology continually changes, contact the Emission Factor and Inventory Group (EFIG) for the latest specific formats. You can find information on the current formats at the following Internet address: http://www.epa.gov/​ttn/​chief/​nif/​index.html. You may also call the air emissions contact in your EPA Regional Office or our Info CHIEF help desk at (919) 541-1000 or e-mail to info.chief@epa.gov.

Where should my State report the data?

(a) Your State submits or reports data by providing it directly to EPA.

(b) The latest information on data reporting procedures is available at the following Internet address: http://www.epa.gov/​ttn/​chief. You may also call our Info CHIEF help desk at (919) 541-1000 or e-mail to info.chief@epa.gov.

Appendix A to Subpart A of Part 51—Tables and Definitions

Table 1.—Emission Thresholds by Pollutant (tpy1) for Treatment of Point Sources as Type A Under § 51.30

PollutantEmissions threshold for type A treatment
1. SO2≥2500
2. VOC≥250
3. NOX≥2500
4. CO≥2500
5. PbDoes not determine Type A status
6. PM10≥250
7. PM2.5≥250
8. NH32≥250
1 tpy = tons per year of actual emissions.
2 Ammonia threshold applies only in areas where ammonia emissions are a factor in determining whether a source is a major source, i.e., where ammonia is considered a significant precursor of PM2.5.

Table 2a.—Data Elements for Reporting on Emissions From Point Sources, Where Required by § 51.30

Data elementsEvery-year reportingThree-year reporting
1. Inventory year
2. Inventory start date
3. Inventory end date
4. Inventory type
5. FIPS code
6. Facility ID codes
7. Unit ID code
8. Process ID code
9. Stack ID code
10. Site name
11. Physical address
Start Printed Page 32725
12. SCC or PCC
13. Heat content (fuel) (annual average)
14. Heat content (fuel) (ozone season, if applicable)
15. Ash content (fuel)(annual average)
16. Sulfur content (fuel)(annual average)
17. Pollutant code
18. Activity/throughput (for each period reported)
19. Summer daily emissions (if applicable)
20. Ozone season emissions (if applicable)
21. Annual emissions
22. Emission factor
23. Winter throughput (percent)
24. Spring throughput (percent)
25. Summer throughput (percent)
26. Fall throughput (percent)
27. Hr/day in operation
28. Start time (hour)
29. Day/wk in operation
30. Wk/yr in operation
31. X stack coordinate (longitude) with method accuracy descriptions
32. Y stack coordinate (latitude) with method accuracy descriptions
33. Stack height
34. Stack diameter
35. Exit gas temperature
36. Exit gas velocity
37. Exit gas flow rate
38. SIC/NAICS and at the facility and unit levels
39. Design capacity (including boiler capacity if applicable)
40. Maximum generator nameplate capacity
41. Primary capture and control efficiencies (percent)
42. Total capture and control efficiency (percent)
43. Control device type
44. Rule effectiveness (percent)

Table 2b.—Data Elements for Reporting on Emissions From Non-Point Sources and Nonroad Mobile Sources, Where Required by § 51.30

Data elementsEvery-year reportingThree-year reporting
1. Inventory year
2. Inventory start date
3. Inventory end date
4. Inventory type
5. FIPS code
6. SCC or PCC
7. Emission factor
8. Activity/throughput level (for each period reported)
9. Total capture/control efficiency (percent)
10. Rule effectiveness (percent)
11. Rule penetration (percent)
12. Pollutant code
13. Ozone season emissions (if applicable)
14. Summer daily emissions (if applicable)
15. Annual emissions
16. Winter throughput (percent)
17. Spring throughput (percent)
18. Summer throughput (percent)
19. Fall throughput (percent)
20. Hrs/day in operation
21. Days/wk in operation
22. Wks/yr in operation
Start Printed Page 32726

Table 2c.—Data Elements for Reporting on Emissions From Onroad Mobile Sources, Where Required by § 51.30

Data elementsEvery-year reportingThree-year reporting
1. Inventory year
2. Inventory start date
3. Inventory end date
4. Inventory type
5. FIPS code
6. SCC or PCC
7. Emission factor
8. Activity (VMT by SCC)
9. Pollutant code
10. Ozone season emissions (if applicable)
11. Summer daily emissions (if applicable)
12. Annual emissions
13. Winter throughput (percent)
14. Spring throughput (percent)
15. Summer throughput (percent)
16. Fall throughput (percent)

Definitions

Activity throughput—A measurable factor or parameter that relates directly or indirectly to the emissions of an air pollution source during the period for which emissions are reported. Depending on the type of source category, activity information may refer to the amount of fuel combusted, raw material processed, product manufactured, or material handled or processed. It may also refer to population, employment, or number of units. Activity information is typically the value that is multiplied against an emission factor to generate an emissions estimate.

Annual emissions—Actual emissions for a plant, point, or process—measured or calculated that represent a calendar year.

Ash content—Inert residual portion of a fuel.

Biogenic sources—Biogenic emissions are all pollutants emitted from non-anthropogenic sources. Example sources include trees and vegetation, oil and gas seeps, and microbial activity.

Control device type—The name of the type of control device (e.g., wet scrubber, flaring, or process change).

Day/wk in operations—Days per week that the emitting process operates—average over the inventory period.

Design capacity—A measure of the size of a point source, based on the reported maximum continuous throughput or output capacity of the unit. For a boiler, design capacity is based on the reported maximum continuous steam flow, usually in units of million BTU per hour.

Emission factor—Ratio relating emissions of a specific pollutant to an activity or material throughput level.

Exit gas flow rate—Numeric value of stack gas's flow rate.

Exit gas temperature—Numeric value of an exit gas stream's temperature.

Exit gas velocity—Numeric value of an exit gas stream's velocity.

Facility ID codes—Unique codes for a plant or facility treated as a point source, containing one or more pollutant-emitting units. The EPA's reporting format for a given reporting year may require several facility ID codes to ensure proper matching between data bases, e.g., the State's own current and most recent facility ID codes, the EPA-assigned facility ID codes, and the ORIS (Department of Energy) ID code if applicable.

Fall throughput (percent)—Part of the throughput for the three Fall months (September, October, November). This expresses part of the annual activity information based on four seasons—typically spring, summer, fall, and winter. It can be a percentage of the annual activity (e.g., production in summer is 40 percent of the year's production) or units of the activity (e.g., out of 600 units produced, spring = 150 units, summer = 250 units, fall = 150 units, and winter = 50 units).

FIPS Code—Federal Information Placement System (FIPS)is the system of unique numeric codes the government developed to identify States, counties and parishes for the entire United States, Puerto Rico, and Guam.

Heat content—The amount of thermal heat energy in a solid, liquid, or gaseous fuel, averaged over the period for which emissions are reported. Fuel heat content is typically expressed in units of Btu/lb of fuel, Btu/gal of fuel, joules/kg of fuel, etc.

Hr/day in operations—Hours per day that the emitting process operates—average over the inventory period.

Inventory end date—Last day of the inventory period.

Inventory start date—First day of the inventory period.

Inventory type—A code indicating whether the inventory submission includes emissions of hazardous air pollutants.

Inventory year—The calendar year for which you calculated emissions estimates.

Lead (Pb)—As defined in 40 CFR 50.12, lead should be reported as elemental lead and its compounds.

Maximum nameplate capacity—A measure of the size of a generator which is put on the unit's nameplate by the manufacturer. The data element is reported in megawatts or kilowatts.

Mobile source—A motor vehicle, nonroad engine or nonroad vehicle, where:

A “motor vehicle” is any self-propelled vehicle used to carry people or property on a street or highway.

A “nonroad engine” is an internal combustion engine (including fuel system) that is not used in a motor vehicle or vehicle only used for competition, or that is not affected by §§ 111 or 202 of the CAA.

A “nonroad vehicle” is a vehicle that is run by a nonroad engine and that is not a motor vehicle or a vehicle only used for competition.

Nitrogen oxides (NOX)—The EPA has defined nitrogen oxides (NOX) in 40 CFR part 60.2 as all oxides of nitrogen except N2 O. Nitrogen Oxides should be reported on an equivalent molecular weight basis as nitrogen dioxide (NO2).

Non-point sources—Non-point sources collectively represent Start Printed Page 32727individual sources that have not been inventoried as specific point, mobile, or biogenic sources. These individual sources treated collectively as non-point sources are typically too small, numerous, or difficult to inventory using the methods for the other classes of sources.

Ozone Season—The period May 1 through September 30 of a year.

PM (Particulate Matter)—Particulate matter is a criteria air pollutant. For the purpose of this subpart, the following definitions apply:

(1) Filterable PM2.5 or Filterable PM10: Particles that are directly emitted by a source as a solid or liquid at stack or release conditions and captured on the filter of a stack test train. Filterable PM2.5 is particulate matter with an aerodynamic diameter equal to or less than 2.5 micrometers. Filterable PM10 is particulate matter with an aerodynamic diameter equal to or less than 10 micrometers.

(2) Condensible PM: Material that is vapor phase at stack conditions, but which condenses and/or reacts upon cooling and dilution in the ambient air to form solid or liquid PM immediately after discharge from the stack. Note that all condensible PM, if present from a source, is typically in the PM2.5 size fraction, and therefore all of it is a component of both primary PM2.5 and primary PM10.

(3) Primary PM2.5: The sum of filterable PM2.5 and condensible PM.

(4) Primary PM10: The sum of filterable PM10 and condensible PM.

(5) Secondary PM: Particles that form or grow in mass through chemical reactions in the ambient air well after dilution and condensation have occurred. Secondary PM is usually formed at some distance downwind from the source. Secondary PM should not be reported in the emission inventory and is not covered by this subpart.

PCC—Process classification code. A process-level code that describes the equipment or operation which is emitting pollutants. This code is being considered as a replacement for the SCC.

Physical address—Street address of a facility. This is the address of the location where the emissions occur; not, for example, the corporate headquarters.

Point source—Point sources are large, stationary (non-mobile), identifiable sources of emissions that release pollutants into the atmosphere. As used in this rule, a point source is defined as a facility that is a major source under § 302 or part D of title I of the Clean Air Act. Emissions of hazardous air pollutants are not considered in determining whether a source is a point source under this subpart.

Pollutant code—A unique code for each reported pollutant assigned by the reporting format specified by EPA for each reporting year.

Primary capture and control efficiencies (percent)—Two values indicating the emissions capture efficiency and the emission reduction efficiency of a primary control device. Capture and control efficiencies are usually expressed as a percentage or in tenths.

Process ID code—Unique code for the process generating the emissions, typically a description of a process.

Roadway class—A classification system developed by the Federal Highway Administration that defines all public roadways as to type based on land use and physical characteristics of the roadway.

Rule effectiveness (RE)—How well a regulatory program achieves all possible emission reductions. This rating reflects the assumption that controls typically are not 100 percent effective because of equipment downtime, upsets, decreases in control efficiencies, and other deficiencies in emission estimates. RE adjusts the control efficiency.

Rule penetration—The percentage of a non-point source category covered by an applicable regulation.

SCC—Source classification code. A process-level code that describes the equipment and/or operation which is emitting pollutants.

SIC/NAICS—Standard Industrial Classification code. NAICS (North American Industry Classification System) codes will replace SIC codes. U.S. Department of Commerce's code for businesses by products or services.

Site name—The name of the facility.

Spring throughput (percent)—Part of throughput or activity for the three spring months (March, April, May). See the definition of Fall Throughput.

Stack diameter—A stack's inner physical diameter.

Stack height—A stack's physical height above the surrounding terrain.

Stack ID code—Unique code for the point where emissions from one or more processes release into the atmosphere.

Start time (hour)—Start time (if available) that was applicable and used for calculations of emissions estimates.

Sulfur content—Sulfur content of a fuel, usually expressed as percent by weight.

Summer daily emissions—Average day's emissions for a typical summer day with conditions critical to ozone attainment planning. The State will select the particular month(s) in summer and the day(s) in the week to be represented. The selection of conditions should be coordinated with the conditions assumed in the development of reasonable further progress plans, rate of progress plans and demonstrations, and/or emissions budgets for transportation conformity, to allow comparability of daily emission estimates.

Summer throughput (percent)—Part of throughput or activity for the three summer months (June, July, August). See the definition of Fall Throughput.

Total capture and control efficiency (percent)—The net emission reduction efficiency of all emissions collection and devices.

Type A source—Large point sources with actual annual emissions greater than or equal to any of the emission thresholds listed in Table 1 for Type A sources.

Unit ID code—Unique code for the unit of generation of emissions, typically a physical piece or closely related set of equipment. The EPA's reporting format for a given reporting year may require multiple unit ID codes to ensure proper matching between data bases, e.g., the State's own current and most recent unit ID codes, the EPA-assigned unit ID codes if any, and the ORIS (Department of Energy) ID code if applicable.

VMT by SCC—Vehicle miles traveled (VMT) disaggregated to the SCC level, i.e., reflecting combinations of vehicle type and roadway class. VMT expresses vehicle activity and is used with emission factors. The emission factors are usually expressed in terms of grams per mile of travel. Because VMT does not correlate directly to emissions that occur while the vehicle isn't moving, these nonmoving emissions are incorporated into the emission factors in EPA's MOBILE Model.

VOC—Volatile Organic Compounds. The EPA's regulatory definition of VOC is in 40 CFR 51.100.

Winter throughput (percent)—Part of throughput or activity for the three winter months (December, January, February, all from the same year, e.g., Winter 2000 = January 2000 + February, 2000 + December 2000). See the definition of Fall Throughput.

Wk/yr in operation—Weeks per year that the emitting process operates.

X stack coordinate (longitude)—An object's east-west geographical coordinate.

Y stack coordinate (latitude)—An object's north-south geographical coordinate. Start Printed Page 32728

Appendix B to Subpart A of Part 51—[Reserved]

3. Part 51 is amended by revising § 51.122 of subpart G to read as follows:

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

(a) For its transport SIP revision under § 51.121 of this part, each State must submit to EPA NOX emissions data as described in this section.

(b) Each revision must provide for periodic reporting by the State of NOX emissions data to demonstrate whether the State's emissions are consistent with the projections contained in its approved SIP submission.

(1) Every-year reporting cycle. Each revision must provide for reporting of NOX emissions data every year as follows:

(i) The State must report to EPA emissions data from all NOX sources within the State for which the State specified control measures in its SIP submission under § 51.121(g) of this part. This would include all sources for which the State has adopted measures that differ from the measures incorporated into the baseline inventory for the year 2007 that the State developed in accordance with § 51.121(g) of this part.

(ii) If sources report NOX emissions data to EPA for a given year pursuant to a trading program approved under § 51.121(p) of this part or pursuant to the monitoring and reporting requirements of subpart H of 40 CFR part 75, then the State need not provide an every-year cycle report to EPA for such sources.

(2) Three-year cycle reporting. Each plan must provide for triennial (i.e., every third year) reporting of NOX emissions data from all sources within the State.

(3) The data availability requirements in § 51.116 of this part must be followed for all data submitted to meet the requirements of paragraphs (b)(1) and (2) of this section.

(c) The data reported in paragraph (b) of this section must meet the requirements of subpart A of this part.

(d) Approval of ozone season calculation by EPA. Each State must submit for EPA approval an example of the calculation procedure used to calculate ozone season emissions along with sufficient information to verify the calculated value of ozone season emissions.

(e) Reporting schedules.

(1) Data collection is to begin during the ozone season one year prior to the State's NOX SIP Call compliance date.

(2) Reports are to be submitted according to paragraph (b) of this section and the schedule in Table 1. After 2008, triennial reports are to be submitted every third year and annual reports are to be submitted each year that a triennial report is not required.

Table 1.—Schedule for Submitting Reports

Data collection yearType of report required
2002Triennial.
2003Annual.
2004Annual.
2005Triennial.
2006Annual.
2007Annual.
2008Triennial.

(3) States must submit data for a required year no later than 17 months after the end of the calendar year for which the data are collected.

(f) Data reporting procedures are given in subpart A. When submitting a formal NOX Budget Emissions Report and associated data, States shall notify the appropriate EPA Regional Office.

(g) Definitions. As used in this section, words and terms shall have the meanings set forth in appendix A of subpart A of this part.

4. Part 51 is amended by adding § 51.123 to Subpart G to read as follows:

Findings and requirements for submission of State implementation plan revisions relating to emissions of oxides of nitrogen pursuant to the Clean Air Interstate Rule.

(a) Under section 110(a)(1) of the CAA, 42 U.S.C. 7410(a)(1), the Administrator determines that each State identified in paragraph (c) of this section must submit a SIP revision to comply with the requirements of section 110(a)(2)(D)(i)(I) of the CAA, 42 U.S.C. 7410(a)(2)(D)(i)(I), through the adoption of adequate provisions prohibiting sources and other activities from emitting NOX in amounts that will contribute significantly to nonattainment in, or interfere with maintenance by, one or more other States with respect to the fine particles (PM2.5) and/or the 8-hour ozone NAAQS.

(b) For each State identified in paragraph (c) of this section, the SIP revision required under paragraph (a) will contain adequate provisions, for purposes of complying with § 110(a)(2)(D)(i)(I) of the CAA, 42 U.S.C. 7410(a)(2)(D)(i)(I), only if the SIP revision contains measures that assure compliance with the applicable requirements of this section.

(c) The following States are subject to the requirements of this section: Alabama, Arkansas, Connecticut, Delaware, Florida, Georgia, Illinois, Indiana, Iowa, Kansas, Kentucky, Louisiana, Maryland, Massachusetts, Michigan, Minnesota, Mississippi, Missouri, New Jersey, New York, North Carolina, Ohio, Pennsylvania, South Carolina, Tennessee, Texas, Virginia, West Virginia, Wisconsin, and the District of Columbia, provided that Connecticut shall be subject to a seasonal NOX reduction requirement, unless it adopts an annual NOX reduction requirement, as described in paragraph (q) of this section.

(d)(1) The SIP submissions required under paragraph (a) of this section must be submitted to EPA by no later than 18 months from the date of promulgation of the final Clean Air Interstate Rule.

(2) The requirements of appendix V shall apply to the SIP submissions required under paragraph (a) of this section.

(3) The State shall deliver 5 copies of the SIP revision to the appropriate Regional Office, with a letter giving notice of such action.

(e)(1)(i) The Annual EGU NOX budget for a State is defined as the total amount of NOX emissions from all EGUs in that State for a year if the State meets the requirements of paragraph (a) of this section by imposing control measures, at least in part, on EGUs. If a State imposes control measures under this section on only EGUs, the Annual EGU NOX budget amounts for a State shall not exceed the amounts, during the indicated periods, specified in paragraph (e)(2) of this section.

(ii) The Non-EGU Reduction Requirement is defined as the amount of NOX emission reductions the State demonstrates, in accordance with paragraph (g) of this section, it will achieve from non-EGUs during the appropriate period. If a State meets the requirements of paragraph (a) of this section by imposing control measures on only non-EGUs, the State's Non-EGU Reduction Requirement shall equal or exceed the amount specified in paragraph (e)(3) of this section.

(iii) If a State meets the requirements of paragraph (a) of this section by imposing control measures on both EGUs and non-EGUs, the amount of the Non-EGU Reduction Requirement shall equal or exceed the difference between the amount of the State's Annual EGU NOX budget specified in paragraph (e)(2) of this section and the amount of the State's Annual EGU NOX budget specified in the SIP for the appropriate period. Start Printed Page 32729

(2) For a State that complies with the requirements of paragraph (a) of this section by imposing control measures only on EGUs, the amount of the Annual EGU NOX budget, in tons per year, shall be as follows, for the indicated State, for the indicated period:

StateAnnual EGU NOX budget, 2010 through 2014Annual EGU NOX budget, 2015 and beyond
Alabama67,42256,185
Arkansas24,91920,765
Delaware5,0894,241
District of Columbia215179
Florida115,50396,253
Georgia63,57552,979
Illinois73,62261,352
Indiana102,29585,246
Iowa30,45825,381
Kansas32,43627,030
Kentucky77,93864,948
Louisiana47,33939,449
Maryland26,60722,173
Massachusetts19,63016,358
Michigan60,21250,177
Minnesota29,30324,420
Mississippi21,93218,277
Missouri56,57147,143
New Jersey9,8958,246
New York52,50343,753
North Carolina55,76346,469
Ohio101,70484,753
Pennsylvania84,55270,460
South Carolina30,89525,746
Tennessee47,73939,783
Texas224,314186,928
Virginia31,08725,906
West Virginia68,23556,863
Wisconsin39,04432,537
Total1,600,7991,333,999

(3) For a State that complies with the requirements of paragraph (a) of this section by imposing control measures on only non-EGUs, the amount of the Non-EGU Reduction Requirement, in tons per year, shall be as follows, for the indicated State, for the indicated period:

StateNon-EGU reduction requirement, 2010 through 2014 1Non-EGU reduction requirement, 2015 and beyond 2
Alabama66,67872,415
Arkansas27,58132,035
Delaware5,2116,559
District of Columbia00
Florida46,09774,247
Georgia87,025100,321
Illinois96,778117,148
Indiana133,705156,754
Iowa51,64261,219
Kansas68,46474,870
Kentucky115,962133,752
Louisiana2,36110,651
Maryland33,79339,727
Massachusetts00
Michigan60,68876,323
Minnesota71,69780,280
Mississippi21,16826,623
Missouri76,22993,657
New Jersey19,10522,154
New York11,49721,747
North Carolina5,23715,931
Ohio159,696171,147
Pennsylvania123,148142,440
Start Printed Page 32730
South Carolina33,80540,454
Tennessee55,06162,917
Texas013,572
Virginia23,81331,394
West Virginia86,96591,337
Wisconsin66,45664,863
1 This period refers to each year during the 2010-2014 period.
2 This period refers to each year during 2015 and subsequently.

(f) Each SIP revision must set forth control measures to meet the amounts specified in paragraph (e) of this section, as applicable, including the following:

(1) A description of enforcement methods including, but not limited to:

(i) Procedures for monitoring compliance with each of the selected control measures;

(ii) Procedures for handling violations; and

(iii) A designation of agency responsibility for enforcement of implementation.

(2)(i) Should a State elect to impose control measures on EGUs, then those measures must impose a NOX mass emissions cap on all such sources in the State.

(ii) Should a State elect to impose control measures on fossil fuel-fired non-EGUs that are boilers or combustion turbines with a maximum design heat input greater than 250 mmBtu/hr, then those measures must impose a NOX mass emissions cap on all such sources in the State.

(iii) Should a State elect to impose control measures on fossil fuel-fired non-EGUs other than those described in paragraph (f)(2)(ii) of this section, then those measures must impose a NOX mass emissions cap on all such sources in the State, or the State must demonstrate why such emissions cap is not practicable, and adopt alternative requirements that ensure to the maximum practicable degree that the State will comply with its requirements under paragraph (e) of this section, as applicable, in 2010 and subsequent years. (g)(1) Each SIP revision which includes control measures covering non-EGUs as part or all of a State's obligation in meeting its requirement under paragraph (a) of this section must demonstrate that such control measures are adequate to provide for the timely compliance with the State's Non-EGU Reduction Requirement under paragraph (e) of this section, and are not otherwise required under the Clean Air Act.

(2) The demonstration under paragraph (g)(1) of this section must include the following, with respect to each source category of non-EGUs for which the SIP requires controls:

(i) A detailed historical baseline inventory of NOX mass emissions from the source category in a representative year consisting, at the State's election, of 2002, 2003, 2004, or 2005, or an average of 2 or more of those years, absent the control measures specified in the SIP submission.

(A) This inventory must represent estimates of actual emissions based on part 75 monitoring data, if the source category is subject to part 75 monitoring requirements.

(B) In the absence of part 75 monitoring data, actual emissions must be estimated using assumptions that ensure a source or source category's actual emissions are not overestimated, and must include source-specific or category-specific data. If a State uses factors to estimate emissions, production or utilization, or effectiveness of controls or rules for a source category, such factors must be chosen to ensure that emissions are not overestimated, or the State must justify the use of another value with additional information showing with reasonable confidence that the substitute value is more appropriate for estimating actual emissions.

(C) For measures to reduce emissions from motor vehicles, emission estimates must be based on an emissions model that has been approved by EPA for use in SIP development, and must be consistent with the planning assumptions regarding vehicle miles traveled and other factors current at the time of the SIP development.

(D) For measures to reduce emissions from nonroad engines or vehicles, emission estimates must be based on the emission methodologies recommended in EPA guidance current at the time of the SIP development or the SIP must document that another method is superior due to local factors.

(ii) A detailed baseline inventory of NOX mass emissions from the source category in the years 2010 and 2015, absent the control measures specified in the SIP submission, and reflecting changes in these emissions from the historical baseline year to the years 2010 and 2015, based on projected changes in the production input and/or output, population, vehicle miles traveled, economic activity or other factors as applicable to this source category.

(A) These inventories must account for implementation of any rules or regulations that will affect NOX emissions from this source category, excluding any control measures specified in the SIP submission to meet the NOX emissions reduction requirements of this section.

(B) Economic and population forecasts must be as specific as possible to the applicable industry, State, and county of the source or source category, 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.

(C) These inventories must account for any changes in production method, materials, fuels, or efficiency that are expected to occur between the historical baseline year and 2010 or 2015, as appropriate.

(iii) A projection of NOX mass emissions in 2010 and 2015 from the source category identified in paragraph (g)(2)(i) of this section resulting from implementation of each of the control Start Printed Page 32731measures specified in the SIP submission.

(A) These inventories must address the possibility that the State's new control measures may cause production and emissions to shift to non-regulated or less stringently regulated sources in the source category in the same or another State, and must include in the projected emissions inventory any such amounts of emissions that may shift to other sources.

(B) The State must provide EPA with a summary of the computations, assumptions, and judgments used to determine the degree of reduction in projected 2010 and 2015 NOX emissions that will be achieved from the implementation of the new control measures compared to the relevant baseline emissions inventory.

(iv) The result of subtracting the amounts in paragraph (g)(2)(iii) for 2010 and 2015, respectively, from the lower of the amounts in paragraph (g)(2)(i) or (g)(2)(ii) of this section for 2010 and 2015, respectively, may be credited towards the State's Non-EGU Reduction Requirement in paragraph (e)(3) of this section for the appropriate period.

(v) Each revision must identify the sources of the data used in the estimate and projection of emissions.

(h) Each revision must comply with § 51.116 (regarding data availability).

(i) Each revision must provide for monitoring the status of compliance with any control measures adopted to meet the State's requirements under paragraph (e) of this section. Specifically, the revision must meet the following requirements:

(1) The revision must provide for legally enforceable procedures for requiring owners or operators of stationary sources to maintain records of, and periodically report to the State:

(i) Information on the amount of NOX emissions from the stationary sources; and

(ii) Other information as may be necessary to enable the State to determine whether the sources are in compliance with applicable portions of the control measures;

(2) The revision must comply with § 51.212 (regarding testing, inspection, enforcement, and complaints);

(3) If the revision contains any transportation control measures, then the revision must comply with § 51.213 (regarding transportation control measures);

(4)(i) If the revision contains measures to control EGUs, then the revision must require such sources to comply with the monitoring and reporting provisions of subpart H of part 75.

(ii) If the revision contains measures to control fossil fuel-fired non-EGUs that are boilers or combustion turbines with a maximum design heat input greater than 250 mmBtu/hr, then the revision must require such sources to comply with the monitoring and reporting provisions of subpart H of part 75.

(iii) If the revision contains measures to control any other non-EGUs that are not described in paragraph (i)(4)(ii) of this section, the revision must require such sources to comply with the monitoring and reporting provisions of subpart H of part 75, or the State must demonstrate why such requirements are not practicable, and adopt alternative requirements that ensure to the maximum practicable degree that the required emissions reductions will be achieved.

(j) Each revision must show that the State has legal authority to carry out the revision, including authority to:

(1) Adopt emissions standards and limitations and any other measures necessary for attainment and maintenance of the State's relevant Annual EGU NOX budget or the Non-EGU Reduction Requirement, as applicable, under paragraph (e);

(2) Enforce applicable laws, regulations, and standards, and seek injunctive relief;

(3) Obtain information necessary to determine whether air pollution sources are in compliance with applicable laws, regulations, and standards, including authority to require recordkeeping and to make inspections and conduct tests of air pollution sources; and

(4)(i) Require owners or operators of stationary sources to install, maintain, and use emissions monitoring devices and to make periodic reports to the State on the nature and amounts of emissions from such stationary sources; and

(ii) Make the data described in paragraph (j)(4)(i) of this section available to the public as reported and as correlated with any applicable emissions standards or limitations.

(k)(1) The provisions of law or regulation which the State determines provide the authorities required under this section must be specifically identified, and copies of such laws or regulations must be submitted with the SIP revision.

(2) Legal authority adequate to fulfill the requirements of paragraphs (j)(3) and (4) of this section may be delegated to the State under § 114 of the CAA.

(l)(1) A revision may assign legal authority to local agencies in accordance with § 51.232.

(2) Each revision must comply with § 51.240 (regarding general plan requirements).

(m) Each revision must comply with § 51.280 (regarding resources).

(n) Each revision must provide for State compliance with the reporting requirements set forth in § 51.125.

(o)(1) Notwithstanding any other provision of this section, if a State adopts regulations substantively identical to subparts AA through HH of part 96 of this chapter, (the model CAIR NOX trading program), incorporates such part by reference into its regulations, or adopts regulations that differ substantively from such part only as set forth in paragraph (o)(2) of this section, then that portion of the State's SIP revision is automatically approved as meeting the requirement of paragraph (e)(1)(i) of this section, provided that the State has the legal authority to take such action and to implement its responsibilities under such regulations.

(2)(i) If a State adopts an emissions trading program that differs substantively from subparts AA through HH of part 96 of this chapter only as described in paragraph (o)(2)(ii) of this section, then the emissions trading program is approved as set forth in paragraph (o)(1) of this section.

(ii) The State may decline to adopt the allocation provisions set forth in subpart EE of part 96 of this chapter and may instead adopt any methodology for allocating NOX allowances to individual sources, provided that:

(A) The State's methodology does not allow the State to allocate NOX allowances in excess of the total amount of NOX emissions which the State has assigned to its trading program; and

(B) The State's methodology conforms with the timing requirements for submission of allocations to the Administrator set forth in § 96.141 of this chapter.

(3) If a State adopts an emissions trading program that differs substantively from subparts AA through HH of part 96 of this chapter, other than as set forth in paragraph (o)(2)(ii) of this section, then such portion of the trading program is not automatically approved as set forth in paragraph (o)(1) of this section, but will be reviewed by the Administrator for approvability in accordance with the other provisions of this section.

(p)(1) The State may revise its applicable implementation plan to provide that, for each year during which a State imposes controls on EGUs under paragraph (o) of this section, such EGUs shall not be subject to the requirements of the State's applicable implementation plan that meet the requirements of Start Printed Page 32732§ 51.121. The owners and operators of such EGUs shall surrender for deduction by the Administrator any NOX SIP Call allowances allocated to such units for any such year.

(2) Notwithstanding a revision by the State authorized under paragraph (p)(1) of this section, a State's applicable implementation plan that, without such revision, imposes controls on EGUs under § 51.121 determined by the Administrator to meet the requirements of § 51.121 shall be deemed to continue to meet the requirements of § 51.121.(q)(1)(i) The SIP revision required under paragraph (a) of this section for the State of Connecticut must require emissions reductions during the ozone season, which begins May 1 and ends September 30 of any year, commencing with 2010.

(ii) Except as provided under paragraph (q)(2) of this section, the Administrator shall not approve SIP provisions that adopt the model CAIR NOX trading program, under subparts AA through HH of part 96 of this chapter.

(iii) For purposes of determining the applicability of paragraph (e) of this section to the State of Connecticut's SIP revision required under paragraph (a) of this section—

(A) The term “Seasonal EGU NOX budget” shall replace the term “Annual EGU NOX budget;” and

(B) The Seasonal EGU NOX budget, in tons per season, for the State of Connecticut shall be 4,360 for the years 2010 through 2014, and 3,633 for the years 2015 and beyond; and

(C) The amount of the Non-EGU Reduction Requirement, in tons per season, for the State of Connecticut shall be zero, for the years 2010 through 2014, and zero, for the years 2015 and beyond.

(3) In lieu of the SIP provisions required under paragraph (q)(1) of this section, the Administrator may approve a SIP revision adopted by the State of Connecticut that requires annual NOX emissions reductions and that meets the requirements of this section, as revised by this paragraph.

(i) For purposes of paragraph (e)(2) of this section, the Annual EGU NOX budget, in tons per year, for Connecticut shall be 9,283 for the years 2010 through 2014, and 7,735 for the years 2015 and beyond; and

(ii) For purposes of paragraph (e)(3) of this section, the amount of the Non-EGU Reduction Requirement, in tons per year, for Connecticut shall be zero for the years 2010 through 2014, and zero for the years 2015 and beyond.

(4) The Administrator may approve a SIP revision from the State of Connecticut adopted under paragraph (q)(2) of this section that adopts the model CAIR NOX trading program, under subparts AA through HH of part 96 of this chapter.

(r) The terms used in this section shall have the following meanings:

Boiler means an enclosed fossil-or other-fuel-fired combustion device used to produce heat and to transfer heat to recirculating water, steam, or other medium.

Bottoming-cycle cogeneration unit means a cogeneration unit in which the energy input to the unit is first used to produce useful thermal energy and at least some of the reject heat from the useful thermal energy application or process is then used for power production.

CAIR NOX Trading Program means a multi-State nitrogen oxides air pollution control and emission reduction program established by the Administrator in accordance with subparts AA through HH of part 96 of this chapter and this section, as a means of mitigating interstate transport of fine particulates, ozone, and nitrogen oxides.

Cogeneration unit means a unit:

(1) Having equipment used to produce electricity and useful thermal energy for industrial, commercial, heating, or cooling purposes through the sequential use of energy; and

(2) Producing during the 12-month period starting on the date the unit first produces electricity and during any calendar year after which the unit first produces electricity—

(i) For a topping-cycle cogeneration unit,

(A) Useful thermal energy not less than 5 percent of total energy output; and

(B) Useful power that, when added to one-half of useful thermal energy produced, is not less than 42.5 percent of total energy input or, if useful thermal energy produced is less than 15 percent of total energy output, not less than 45 percent of total energy input.

(ii) For a bottoming-cycle cogeneration unit, useful power not less than 45 percent of total energy input.

Combustion turbine means an enclosed device comprising a compressor, a combustor, and a turbine and in which the flue gas resulting from the combustion of fuel in the combustor passes through the turbine, rotating the turbine. A combustion turbine that is combined cycle also includes any associated heat recovery steam generator and steam turbine.

Electric generating unit or EGU means:

(1) Except for a unit under paragraph (2) of this definition, a fossil fuel-fired boiler or combustion turbine serving at any time a generator with nameplate capacity of more than 25 MWe producing electricity for sale; or

(2) A fossil fuel-fired cogeneration unit serving at any time a generator with nameplate capacity of more than 25 MWe and in any year supplying more than one-third of the unit's potential electric output capacity or 219,000 MWh, whichever is greater, to any utility power distribution system for sale.

Fossil fuel means natural gas, petroleum, coal, or any form of solid, liquid, or gaseous fuel derived from such material.

Fossil-fuel-fired means, with regard to a unit, any boiler or turbine combusting any amount of fossil fuel.

Generator means a device that produces electricity.

Maximum design heat input means the maximum amount of fuel per hour (in Btu/hr) that a unit is capable of combusting on a steady state basis, as specified by the manufacturer of the unit as of the initial installation of the unit.

NAAQS means National Ambient Air Quality Standard.

Nameplate capacity means the maximum electrical generating output (in MWe) that a generator can sustain over a specified period of time when not restricted by seasonal or other deratings, as specified by the manufacturer of the generator as of the initial installation of the generator or, if the generator is subsequently modified or reconstructed resulting in an increase in such maximum electrical generating output, as specified by the person conducting the modification or reconstruction.

Non-EGU means a source of NOX emissions that is not an EGU.

NOX means oxides of nitrogen.

NOX Budget Trading Program means a multi-State nitrogen oxide air pollution control and emission reduction program established by air pollution control and emission reduction program established by the Administrator in accordance with subparts A through I of part 96 of this chapter and § 51.121, as a means of mitigating interstate transport of ozone and nitrogen oxides.

NOX SIP Call allowance means a limited authorization issued by the Administrator under the NOX Budget Trading Program to emit up to one ton of nitrogen oxides during the ozone season of the specified year or any year thereafter.

Sequential use of energy means:

(1) For a topping-cycle cogeneration unit, the use of reject heat from power production in a useful thermal energy application or process; or Start Printed Page 32733

(2) For a bottoming-cycle cogeneration unit, the use of reject heat from useful thermal energy application or process in power production.

Topping-cycle cogeneration unit means a cogeneration unit in which the energy input to the unit is first used to produce useful power and at least some of the reject heat from the power production is then used to provide useful thermal energy.

Total energy input means, with regard to a cogeneration unit, total energy of all forms supplied to the cogeneration unit, excluding energy produced by the cogeneration unit itself.

Total energy output means, with regard to a cogeneration unit, the sum of useful power and useful thermal energy produced by the cogeneration unit.

Useful power means, with regard to a cogeneration unit, electricity or mechanical energy made available for use, excluding any such energy used in the power production process (which process includes, but is not limited to, any on-site processing or treatment of fuel combusted at the unit and any on-site emission controls).

Useful thermal energy means, with regard to a cogeneration unit, thermal energy that is:

(1) Made available to an industrial or commercial process, excluding any heat contained in condensate return or makeup water;

(2) Used in a heat application (e.g., space heating or domestic hot water heating); or

(3) Used in a space cooling application (i.e., thermal energy used by an absorption chiller).

Utility power distribution system means the portion of an electricity grid owned or operated by a distribution utility and dedicated to delivering electricity to customers.

5. Part 51 is amended by adding § 51.124 to Subpart G to read as follows:

Findings and requirements for submission of State implementation plan revisions relating to emissions of sulfur dioxide pursuant to the Clean Air Interstate Rule.

(a) Under § 110(a)(1) of the CAA, 42 U.S.C. 7410(a)(1), the Administrator determines that each State identified in paragraph (c) of this section must submit a SIP revision to comply with the requirements of § 110(a)(2)(D)(i)(I) of the CAA, 42 U.S.C. 7410(a)(2)(D)(i)(I), through the adoption of adequate provisions prohibiting sources and other activities from emitting SO2 in amounts that will contribute significantly to nonattainment in, or interfere with maintenance by, one or more other States with respect to the fine particles (PM2.5) NAAQS.

(b) For each State identified in paragraph (c) of this section, the SIP revision required under paragraph (a) will contain adequate provisions, for purposes of complying with § 110(a)(2)(D)(i)(I) of the CAA, 42 U.S.C. 7410(a)(2)(D)(i)(I), only if the SIP revision contains measures that assure compliance with the applicable requirements of this section.

(c) The following States are subject to the requirements of this section: Alabama, Arkansas, Delaware, Florida, Georgia, Illinois, Indiana, Iowa, Kansas, Kentucky, Louisiana, Maryland, Massachusetts, Michigan, Minnesota, Mississippi, Missouri, New Jersey, New York, North Carolina, Ohio, Pennsylvania, South Carolina, Tennessee, Texas, Virginia, West Virginia, Wisconsin, and the District of Columbia.

(d)(1) The SIP submissions required under paragraph (a) of this section must be submitted to EPA by no later than 18 months from the date of promulgation of the final Clean Air Interstate Rule.

(2) The requirements of appendix V shall apply to the SIP submissions required under paragraph (a) of this section.

(3) The State shall deliver 5 copies of the SIP revision to the appropriate Regional Office, with a letter giving notice of such action.

(e)(1)(i) The Annual EGU SO2 budget for a State is defined as the total amount of SO2 emissions from all EGUs in that State for a year if the State meets the requirements of paragraph (a) of this section by imposing control measures, at least in part, on EGUs. If a State imposes control measures under this section on only EGUs, the Annual EGU SO2 budget amounts for a State shall not exceed the amounts, during the indicated periods, specified in paragraph (e)(2) of this section.

(ii) The Non-EGU Reduction Requirement is defined as the amount of SO2 emission reductions the State demonstrates, in accordance with paragraph (g) of this section, it will achieve from non-EGUs during the appropriate period. If a State meets the requirements of paragraph (a) of this section by imposing control measures on only non-EGUs, the State's Non-EGU Reduction Requirement shall equal or exceed the amount specified in paragraph (e)(3) of this section.

(iii) If a State meets the requirements of paragraph (a) of this section by imposing control measures on both EGUs and non-EGUs, the amount of the Non-EGU Reduction Requirement shall equal or exceed the difference between the amount of the State's Annual EGU SO2 budget specified in paragraph (e)(2) of this section and the amount of the State's Annual EGU SO2 budget specified in the SIP for the appropriate period.

(2) For a State that complies with the requirements of paragraph (a) of this section by imposing control measures only on EGUs, the amount of the Annual EGU SO2 budget, in tons per year, shall be as follows, for the indicated State, for the indicated period:

StateAnnual EGU SO2 budget, 2010 through 2014 1Annual EGU SO2 budget, 2015 and beyond 2
Alabama157,582110,307
Arkansas48,70234,091
Delaware22,41115,687
District of Columbia708495
Florida253,450177,415
Georgia213,057149,140
Illinois192,671134,869
Indiana254,599178,219
Iowa64,09544,866
Kansas58,30440,812
Kentucky188,773132,141
Louisiana59,94841,963
Maryland70,69749,488
Massachusetts82,56157,792
Start Printed Page 32734
Michigan178,605125,024
Minnesota49,98734,991
Mississippi33,76323,634
Missouri137,21496,050
New Jersey32,39222,674
New York135,13994,597
North Carolina137,34296,139
Ohio333,520233,464
Pennsylvania275,990193,193
South Carolina57,27140,089
Tennessee137,21696,051
Texas320,946224,662
Virginia63,47844,435
West Virginia215,881151,117
Wisconsin87,26461,085
Total3,863,5662,704,490
1 This period refers to each year during the 2010-2014 period.
2 This period refers to each year during 2015 and subsequently.

(3) For a State that complies with the requirements of paragraph (a) of this section by imposing control measures on only non-EGUs, the amount of the Non-EGU Reduction Requirement, in tons per year, shall be as follows, for the indicated State, for the indicated period:

StateNon-EGU reduction requirement, 2010 through 2014 1Non-EGU reduction requirement, 2015 and beyond 2
Alabama157,582204,857
Arkansas48,70263,312
Delaware22,41129,134
District of Columbia708920
Florida253,450329,485
Georgia213,057276,974
Illinois192,671250,472
Indiana254,599330,978
Iowa64,09583,323
Kansas58,30475,795
Kentucky188,773245,405
Louisiana59,94877,932
Maryland70,69791,906
Massachusetts82,561107,329
Michigan178,605232,187
Minnesota49,98764,983
Mississippi33,76343,892
Missouri137,214178,378
New Jersey32,39242,109
New York135,139175,681
North Carolina137,342178,545
Ohio333,520433,576
Pennsylvania275,990358,787
South Carolina57,27174,452
Tennessee137,216178,380
Texas320,946417,230
Virginia63,47882,521
West Virginia215,881280,645
Wisconsin87,264113,443
1 This period refers to each year during the 2010-2014 period.
2 This period refers to each year during 2015 and subsequently.

(f) Each SIP revision must set forth control measures to meet the amounts specified in paragraph (e) of this section, as applicable, including the following:

(1) A description of enforcement methods including, but not limited to:

(i) Procedures for monitoring compliance with each of the selected control measures;

(ii) Procedures for handling violations; and

(iii) A designation of agency responsibility for enforcement of implementation. Start Printed Page 32735

(2)(i) Should a State elect to impose control measures on EGUs, then those measures must impose a SO2 mass emissions cap on all such sources in the State.

(ii) Should a State elect to impose control measures on fossil fuel-fired non-EGUs that are boilers or combustion turbines with a maximum design heat input greater than 250 mmBtu/hr, then those measures must impose a SO2 mass emissions cap on all such sources in the State.

(iii) Should a State elect to impose control measures on fossil fuel-fired non-EGUs other than those described in paragraph (f)(2)(ii) of this section, then those measures must impose a SO2 mass emissions cap on all such sources in the State, or the State must demonstrate why such emissions cap is not practicable, and adopt alternative requirements that ensure to the maximum practicable degree that the State will comply with its requirements under paragraph (e) of this section, as applicable, in 2010 and subsequent years.

(g)(1) Each SIP revision which includes control measures covering non-EGUs as part or all of a State's obligation in meeting its requirement under paragraph (a) of this section must demonstrate that such control measures are adequate to provide for the timely compliance with the State's Non-EGU Reduction Requirement under paragraph (e) of this section, and are not otherwise required under the Clean Air Act.

(2) The demonstration under paragraph (g)(1) of this section must include the following, with respect to each source category of non-EGUs for which the SIP requires controls:

(i) A detailed historical baseline inventory of SO2 mass emissions from the source category in a representative year consisting, at the State's election, of 2002, 2003, 2004, or 2005, or an average of 2 or more of those years, absent the control measures specified in the SIP submission.

(A) This inventory must represent estimates of actual emissions based on part 75 monitoring data, if the source category is subject to part 75 monitoring requirements.

(B) In the absence of part 75 monitoring data, actual emissions must be estimated using assumptions that ensure a source or source category's actual emissions are not overestimated, and must include source-specific or category-specific data. If a State uses factors to estimate emissions, production or utilization, or effectiveness of controls or rules for a source category, such factors must be chosen to ensure that emissions are not overestimated, or the State must justify the use of another value with additional information showing with reasonable confidence that the substitute value is more appropriate for estimating actual emissions.

(C) For measures to reduce emissions from motor vehicles, emission estimates must be based on an emissions model that has been approved by EPA for use in SIP development, and must be consistent with the planning assumptions regarding vehicle miles traveled and other factors current at the time of the SIP development.

(D) For measures to reduce emissions from nonroad engines or vehicles, emission estimates must be based on the emission methodologies recommended in EPA guidance current at the time of the SIP development or the SIP must document that another method is superior due to local factors.

(ii) A detailed baseline inventory of SO2 mass emissions from the source category in the years 2010 and 2015, absent the control measures specified in the SIP submission, and reflecting changes in these emissions from the historical baseline year to the years 2010 and 2015, based on projected changes in the production input and/or output, population, vehicle miles traveled, economic activity or other factors as applicable to this source category.

(A) These inventories must account for implementation of any rules or regulations that will affect SO2 emissions from this source category, excluding any control measures specified in the SIP submission to meet the SO2 emissions reduction requirements of this section.

(B) Economic and population forecasts must be as specific as possible to the applicable industry, State, and county of the source or source category, 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.

(C) These inventories must account for any changes in production method, materials, fuels, or efficiency that are expected to occur between the historical baseline year and 2010 or 2015, as appropriate.

(iii) A projection of SO2 mass emissions in 2010 and 2015 from the source category identified in paragraph (g)(2)(i) of this section resulting from implementation of each of the control measures specified in the SIP submission.

(A) These inventories must address the possibility that the State's new control measures may cause production and emissions to shift to non-regulated or less stringently regulated sources in the source category in the same or another State, and must include in the projected emissions inventory any such amounts of emissions that may shift to other sources.

(B) The State must provide EPA with a summary of the computations, assumptions, and judgments used to determine the degree of reduction in projected 2010 and 2015 SO2 emissions that will be achieved from the implementation of the new control measures compared to the relevant baseline emissions inventory.

(iv) The result of subtracting the amounts in paragraph (g)(2)(iii) for 2010 and 2015, respectively, from the lower of the amounts in paragraph (g)(2)(i) or (g)(2)(ii) of this section for 2010 and 2015, respectively, may be credited towards the State's Non-EGU Reduction Requirement in paragraph (e)(3) of this section for the appropriate period.

(v) Each revision must identify the sources of the data used in the estimate and projection of emissions.

(h) Each revision must comply with § 51.116 (regarding data availability).

(i) Each revision must provide for monitoring the status of compliance with any control measures adopted to meet the State's requirements under paragraph (e) of this section. Specifically, the revision must meet the following requirements:

(1) The revision must provide for legally enforceable procedures for requiring owners or operators of stationary sources to maintain records of, and periodically report to the State:

(i) Information on the amount of SO2 emissions from the stationary sources; and

(ii) Other information as may be necessary to enable the State to determine whether the sources are in compliance with applicable portions of the control measures;

(2) The revision must comply with § 51.212 (regarding testing, inspection, enforcement, and complaints);

(3) If the revision contains any transportation control measures, then the revision must comply with § 51.213 Start Printed Page 32736(regarding transportation control measures);

(4)(i) If the revision contains measures to control EGUs, then the revision must require such sources to comply with the monitoring and reporting provisions of part 75.

(ii) If the revision contains measures to control fossil fuel-fired non-EGUs that are boilers or combustion turbines with a maximum design heat input greater than 250 mmBtu/hr, then the revision must require such sources to comply with the monitoring and reporting provisions of part 75.

(iii) If the revision contains measures to control any other non-EGUs that are not described in paragraph (i)(4)(ii) of this section, the revision must require such sources to comply with the monitoring and reporting provisions of part 75, or the State must demonstrate why such requirements are not practicable, and adopt alternative requirements that ensure to the maximum practicable degree that the required emissions reductions will be achieved.

(j) Each revision must show that the State has legal authority to carry out the revision, including authority to:

(1) Adopt emissions standards and limitations and any other measures necessary for attainment and maintenance of the State's relevant Annual EGU SO2 budget or the Non-EGU Reduction Requirement, as applicable, under paragraph (e);

(2) Enforce applicable laws, regulations, and standards, and seek injunctive relief;

(3) Obtain information necessary to determine whether air pollution sources are in compliance with applicable laws, regulations, and standards, including authority to require recordkeeping and to make inspections and conduct tests of air pollution sources; and

(4)(i) Require owners or operators of stationary sources to install, maintain, and use emissions monitoring devices and to make periodic reports to the State on the nature and amounts of emissions from such stationary sources; and

(ii) Make the data described in paragraph (j)(4)(i) of this section available to the public as reported and as correlated with any applicable emissions standards or limitations.

(k)(1) The provisions of law or regulation which the State determines provide the authorities required under this section must be specifically identified, and copies of such laws or regulations must be submitted with the SIP revision.

(2) Legal authority adequate to fulfill the requirements of paragraphs (j)(3) and (4) of this section may be delegated to the State under § 114 of the CAA. (l)(1) A revision may assign legal authority to local agencies in accordance with § 51.232.

(2) Each revision must comply with § 51.240 (regarding general plan requirements).

(m) Each revision must comply with § 51.280 (regarding resources).

(n) Each revision must provide for State compliance with the reporting requirements set forth in § 51.125.

(o) Notwithstanding any other provision of this section, if a State adopts regulations substantively identical to subparts AAA through HHH of part 96 of this chapter (CAIR SO2 Emissions Trading Program), or incorporates such part by reference into its regulations, then that portion of the State's SIP revision is automatically approved as meeting the requirements of paragraph (e)(1)(i) of this section, provided that the State has the legal authority to take such action and to implement its responsibilities under such regulations.

(p) For a State that does not adopt regulations in accordance with paragraph (o) of this section:

(1) The sources subject to the Acid Rain Program , in addition to complying with the requirements of § 72.9(c)(1)(i) of this chapter, shall hold the following amounts of Acid Rain allowances, as of the allowance transfer deadline in the source's compliance account—

(i) For each Acid Rain allowance allocated for a year during 2010 through 2014 that is held in order to meet the requirements of § 72.9(c)(1)(i) of this chapter, one additional Acid Rain allowance allocated for a year during 2010 through 2014; and

(ii) For each Acid Rain allowance allocated for a year during 2015 or thereafter held in accordance with § 72.9(c)(1)(i) of this chapter, two additional Acid Rain allowances allocated for a year during 2015 or thereafter.

(2) When the Administrator deducts Acid Rain allowances under § 73.35(b) and (c) of this chapter, the Administrator will also deduct from the source's compliance account the amount of Acid Rain allowances required to be held under paragraph (p)(1) of this section. If the owner and operator of the source fails to hold the Acid Rain allowances required under paragraph (p)(1) of this section, then, for each Acid Rain allowance required but not held, the Administrator will deduct from such compliance account three Acid Rain allowances allocated for the year after the year of the allowance transfer deadline by which the Acid Rain allowances were required to be held.

(q) The terms used in this section shall have the following meanings:

Acid Rain Program means a multi-State sulfur dioxide and nitrogen oxides air pollution control and emissions reduction program established by the Administrator under title IV of the CAA and parts 72 through 78 of this chapter.

Acid Rain allowance means a limited authorization issued by the Administrator under the Acid Rain Program to emit up to one ton of sulfur dioxide during the specified year or any year thereafter.

Allowance transfer deadline means the allowance transfer deadline under the Acid Rain Program, as defined in § 72.2 of this chapter.

Boiler means an enclosed fossil- or other-fuel-fired combustion device used to produce heat and to transfer heat to recirculating water, steam, or other medium.

Bottoming-cycle cogeneration unit means a cogeneration unit in which the energy input to the unit is first used to produce useful thermal energy and at least some of the reject heat from the useful thermal energy application or process is then used for power production.

CAIR SO2Emissions Trading Program means a multi-State sulfur dioxide air pollution control and emission reduction program established by the Administrator in accordance with subparts AAA through HHH of part 96 of this chapter and this section, as a means of mitigating interstate transport of fine particulates.

Cogeneration unit means a unit:

(1) Having equipment used to produce electricity and useful thermal energy for industrial, commercial, heating, or cooling purposes through the sequential use of energy; and

(2) Producing during the 12-month period starting on the date the unit first produces electricity and during any calendar year after which the unit first produces electricity—

(i) For a topping-cycle cogeneration unit,

(A) Useful thermal energy not less than 5 percent of total energy output; and

(B) Useful power that, when added to one-half of useful thermal energy produced, is not less then 42.5 percent of total energy input or, if useful thermal energy produced is less than 15 percent of total energy output, not less than 45 percent of total energy input.

(ii) For a bottoming-cycle cogeneration unit, useful power not less than 45 percent of total energy input. Start Printed Page 32737

Combustion turbine means an enclosed device comprising a compressor, a combustor, and a turbine and in which the flue gas resulting from the combustion of fuel in the combustor passes through the turbine, rotating the turbine. A combustion turbine that is combined cycle also includes any associated heat recovery steam generator and steam turbine.

Compliance account means a compliance account under the Acid Rain Program, as defined in § 72.2 of this chapter.

Electric generating unit or EGU means:

(1) Except for a unit under paragraph (2) of this definition, a fossil fuel-fired boiler or combustion turbine serving at any time a generator with nameplate capacity of more than 25 MWe producing electricity for sale; or

(2) A fossil fuel-fired cogeneration unit serving at any time a generator with nameplate capacity of more than 25 MWe and in any year supplying more than one-third of the unit's potential electric output capacity or 219,000 MWh, whichever is greater, to any utility power distribution system for sale.

Fossil fuel means natural gas, petroleum, coal, or any form of solid, liquid, or gaseous fuel derived from such material.

Fossil-fuel-fired means, with regard to a unit, any boiler or turbine combusting any amount of fossil fuel.

Generator means a device that produces electricity.

Maximum design heat input means the maximum amount of fuel per hour (in Btu/hr) that a unit is capable of combusting on a steady state basis, as specified by the manufacturer of the unit as of the initial installation of the unit.

NAAQS means National Ambient Air Quality Standard.

Nameplate capacity means the maximum electrical generating output (in MWe) that a generator can sustain over a specified period of time when not restricted by seasonal or other deratings, as specified by the manufacturer of the generator as of the initial installation of the generator or, if the generator is subsequently modified or reconstructed resulting in an increase in such maximum electrical generating output, as specified by the person conducting the modification or reconstruction.

Non-EGU means a source of SO2 emissions that is not an EGU.

SO2 means sulfur dioxide.

Sequential use of energy means:

(1) For a topping-cycle cogeneration unit, the use of reject heat from power production in a useful thermal energy application or process; or

(2) For a bottoming-cycle cogeneration unit, the use of reject heat from useful thermal energy application or process in power production.

Topping-cycle cogeneration unit means a cogeneration unit in which the energy input to the unit is first used to produce useful power and at least some of the reject heat from the power production is then used to provide useful thermal energy.

Total energy input means, with regard to a cogeneration unit, total energy of all forms supplied to the cogeneration unit, excluding energy produced by the cogeneration unit itself.

Total energy output means, with regard to a cogeneration unit, the sum of useful power and useful thermal energy produced by the cogeneration unit.

Useful power means, with regard to a cogeneration unit, electricity or mechanical energy made available for use, excluding any such energy used in the power production process (which process includes, but is not limited to, any on-site processing or treatment of fuel combusted at the unit and any on-site emission controls).

Useful thermal energy means, with regard to a cogeneration unit, thermal energy that is:

(1) Made available to an industrial or commercial process, excluding any heat contained in condensate return or makeup water;

(2) Used in a heat application (e.g., space heating or domestic hot water heating); or

(3) Used in a space cooling application (i.e., thermal energy used by an absorption chiller).

Utility power distribution system means the portion of an electricity grid owned or operated by a distribution utility and dedicated to delivering electricity to customers.

6. Part 51 is amended by adding § 51.125 to Subpart G to read as follows:

Emissions reporting requirements for SIP revisions relating to budgets for SO2 and NOX emissions.

(a) For its transport SIP revision under § 51.123 and/or 51.124 of this part, each State must submit to EPA SO2 and/or NOX emissions data as described in this section.

(1) The District of Columbia and following States must report annual (12 months) emissions of SO2 and NOX: Alabama, Arkansas, Delaware, Florida, Georgia, Illinois, Indiana, Iowa, Kansas, Kentucky, Louisiana, Maryland, Massachusetts, Michigan, Minnesota, Mississippi, Missouri, New Jersey, New York, North Carolina, Ohio, Pennsylvania, South Carolina, Tennessee, Texas, Virginia, West Virginia, and Wisconsin.

(2) The District of Columbia and the following States must report ozone season (May 1 through September 30) emissions of NOX: Alabama, Arkansas, Connecticut, Delaware, Georgia, Illinois, Indiana, Iowa, Kentucky, Louisiana, Maryland, Massachusetts, Michigan, Mississippi, Missouri, New Jersey, New York, North Carolina, Ohio, Pennsylvania, South Carolina, Tennessee, Virginia, West Virginia, and Wisconsin.

(b) Each revision must provide for periodic reporting by the State of SO2 and/or NOX emissions data as specified in paragraph (a) of this section to demonstrate whether the State's emissions are consistent with the projections contained in its approved SIP submission.

(1) Every-year reporting cycle. As applicable, each revision must provide for reporting of SO2 and NOX emissions data every year as follows:

(i) The States identified in paragraph (a)(1) of this section must report to EPA annual emissions data every year from all SO2 and NOX sources within the State for which the State specified control measures in its SIP submission under §§ 51.123 and/or 51.124 of this part.

(ii) The States identified in paragraph (a)(2) of this section must report to EPA ozone season and summer daily emissions data every year from all NOX sources within the State for which the State specified control measures in its SIP submission under § 51.123 of this part.

(iii) If sources report SO2 and NOX emissions data to EPA in a given year pursuant to a trading program approved under § 51.123(o) or § 51.124(o) of this part or pursuant to the monitoring and reporting requirements of subpart H of 40 CFR part 75, then the State need not provide annual reporting of these pollutants to EPA for such sources.

(2) Three-year reporting cycle. As applicable, each plan must provide for triennial (i.e., every third year) reporting of SO2 and NOX emissions data from all sources within the State.

(i) The States identified in paragraph (a)(1) of this section must report to EPA annual emissions data every third year from all SO2 and NOX sources within the State.

(ii) The States identified in paragraph (a)(2) of this section must report to EPA ozone season and ozone daily emissions data every third year from all NOX sources within the State. Start Printed Page 32738

(3) The data availability requirements in § 51.116 of this part must be followed for all data submitted to meet the requirements of paragraphs (b)(1)and(2) of this section.

(c) The data reported in paragraph (b) of this section must meet the requirements of subpart A of this part.

(d) Approval of annual and ozone season calculation by EPA. Each State must submit for EPA approval an example of the calculation procedure used to calculate annual and ozone season emissions along with sufficient information for EPA to verify the calculated value of annual and ozone season emissions.

(e) Reporting schedules.

(1) Reports are to begin with data for emissions occurring in the year 2008, which is the first year of the 3-year cycle.

(2) After 2008, 3-year cycle reports are to be submitted every third year and every-year cycle reports are to be submitted each year that a triennial report is not required.

(3) States must submit data for a required year no later than 17 months after the end of the calendar year for which the data are collected.

(f) Data reporting procedures are given in subpart A. When submitting a formal NOX budget emissions report and associated data, States shall notify the appropriate EPA Regional Office.

(g) Definitions. As used in this section, words and terms shall have the meanings set forth in appendix A of subpart A of this part.

7. § 51.308 is amended by revising the introductory text of paragraph (e)(2), paragraphs (e)(3) and (e)(4), and by adding paragraph (e)(5) as follows:

Regional haze program requirements
* * * * *

(e) * * *

(2) A State may opt to implement an emissions trading program or other alternative measure rather than to require sources subject to BART to install, operate and maintain BART. Except as provided in paragraph (e)(3) of this section, to do so, the State must demonstrate that this emissions trading program or other alternative measure will achieve greater reasonable progress than would be achieved through the installation and operation of BART. To make this demonstration, the State must submit an implementation plan containing the following plan elements and include documentation for all required analyses:

* * * * *

(3) A State that opts to participate in the Clean Air Interstate Rule cap-and-trade program under part 96 AAA-EEE need not require affected BART-eligible EGU's to install, operate, and maintain BART. A State that chooses this option may also include provisions for a geographic enhancement to the program to address the requirement under § 51.302(c) related to BART for reasonably attributable impairment from the pollutants covered by the CAIR cap-and-trade program.

(4) After a State has met the requirements for BART or implemented emissions trading program or other alternative measure that achieves more reasonable progress than the installation and operation of BART, BART-eligible sources will be subject to the requirements of § 51.308(d) in the same manner as other sources.

(5) Any BART-eligible facility subject to the requirement under § 51.308(e) to install, operate, and maintain BART may apply to the Administrator for an exemption from that requirement. An application for an exemption will be subject to the requirements of § 51.303(a)(2)-(h).

Start Part

PART 72—PERMITS REGULATION

1. The authority citation for part 72 continues to read as follows:

Start Authority

Authority: 42 U.S.C. 7601 and 7651, et seq.

End Authority
[Amended]

2. Section 72.2 is amended as follows:

a. Amend the definition of “Acid rain emissions limitation” by replacing, in paragraph (1)(i), the words “an affected unit” by the words “the affected units at a source” and replacing, in paragraph (1)(ii)(C), the words “compliance subaccount for that unit” by the words “compliance account for that source”;

b. Amend the definition of “Allocate or allocation” by replacing the words “unit account” by the words “compliance account”;

c. Amend the definition of “Allowance deduction, or deduct” by replacing the words “compliance subaccount, or future year subaccount,” by the words “compliance account” and replacing the words “from an affected unit” by the words “from the affected units at an affected source”;

d. Amend the definition of “Allowance transfer deadline” by replacing the words “affected unit's compliance subaccount” by the words “an affected source's compliance account” and replacing the words “the unit's” by the words “the source's”;

e. Amend the definition of “Authorized account representative” by replacing the words “unit account” by the words “compliance account” and replacing the words “affected unit” by the words “affected source and the affected units at the source”;

f. Amend the definition of “Compliance use date” by replacing the word “unit's” by the word “source's”;

g. Amend the definition of “excess emissions” by, in paragraph (1), replacing the words “an affected unit” by the words “the affected units at an affected source” and replacing the words “for the unit” by the words “for the source”;

h. Amend the definition of “Recordation, record, or recorded” by removing the words “or subaccount”; and

i. Revise the definition of “Cogeneration unit”, adding a new definition of “Compliance account”, and removing the definitions of “Compliance subaccount”, “Current year subaccount”, “Future year subaccount”, and “Unit account” to read as follows:

Definitions.
* * * * *

Cogeneration unit means a unit that has equipment used to produce electric energy and forms of useful thermal energy (such as heat or steam) for industrial, commercial, heating, or cooling purposes, through sequential use of energy.

* * * * *

Compliance account means an Allowance Tracking System account, established by the Administrator for an affected source and for each affected unit at the source pursuant to § 73.31(a) or (b) of this chapter.

* * * * *
[Amended]

3. Section 72.7 is amended in paragraph (c)(1)(ii), in the first sentence, remove the word “unit's” and add after the words “Allowance Tracking System account” the words “of the source that includes the unit” and remove the third sentence.

[Amended]

4. Section 72.9 is amended by:

a. In paragraph (c)(1)(i), replace the words “unit's compliance subaccount” with the words “source's compliance account” and replace the words “from the unit” by the words “from the affected units at the source”;

b. In paragraphs (e)(1) and (e)(2) introductory text, replace the words “an affected unit” by the words “an affected source”; and

c. In paragraph (g)(6), remove the second sentence.

Start Printed Page 32739
[Amended]

5. Section 72.21 is amended by removing from paragraph (b)(1) the word “affected” wherever it appears.

[Amended]

6. Section 72.24 is amended by removing and reserving paragraphs (a)(5), (a)(7), and (a)(10).

[Amended]

7. Section 72.40 is amended, in paragraph (a)(1), replace the words “unit's compliance subaccount” with the words “compliance account of the source where the unit is located ”, remove the words “, or in the compliance subaccount of another affected unit at the source to the extent provided in § 73.35(b)(3),”, and replace the words “from the unit” by the words “from the affected units at the source”.

[Amended]

8. Section 72.73 is amended, in paragraph (b)(2), replace the words “the first Acid Rain permit” by the words “an Acid Rain permit”.

[Amended]

9. Section 72.90 is amended, in paragraph (a), add, after the words “each calendar year”, the words “during 1995 through 2004”.

[Amended]

10. Section 72.95 is amended by:

a. In the introductory text, replace the words “an affected unit's compliance subaccount” with the words “an affected source's compliance account”; and

b. In paragraph (a), replace the words “by the unit” by the words “by the affected units at the source”.

End Part Start Part

PART 73—SULFUR DIOXIDE ALLOWANCE SYSTEM

1. The authority citation continues to read as follows:

Start Authority

Authority: 42 U.S.C. 7601 and 7651, et seq.

End Authority
[Amended]

2. Section 73.10 is amended by:

a. In paragraph (a), remove the words “in each future year subaccount”;

b. In paragraph (b)(1), replace the words “in the future year subaccounts representing calendar years” with the words “for the years”; and

c. In paragraph (b)(2), replace the words “in the future year subaccounts representing calendar years” with the words “for the year”.

[Amended]

3. Section 73.30 is amended by:

a. In paragraph (a), replace the words “affected units” by the words “affected sources”; and

b. In paragraph (b), replace the word “unit” by the word “source”.

[Amended]

4. Section 73.31 is amended by:

a. In paragraph (a), replace the words “each unit” with the words “each source that includes a unit”;

b. In paragraph (b), replace the words “the unit.” by the words “the source that includes the unit, unless the source already has a compliance account.”; and

c. In paragraph (c)(1)(v), remove the words “ I shall abide by any fiduciary responsibilities assigned pursuant to the binding agreement.”.

[Removed and Reserved]

5. § 73.32 is removed and reserved.

[Amended]

6. Removing and reserving paragraph (c).

[Amended]

7. Section 73.34 is amended as follows:

a. Revise paragraph (a) to read as set forth below;

b. Remove and reserve paragraph (b); and

c. In paragraph (c) heading, replace the words “in subaccounts” with the words “in compliance accounts” and in the introductory text, replace the words “compliance, current year, and future year” with the words “compliance account”.

Recordation in accounts.

(a) Recordation in compliance accounts. When a compliance account is established under § 73.31(a), the Administrator will record in the account any allowances allocated to the affected units at the source under § 73.10 or part 74 for 30 years starting with the later of 1995 or the year in which the account is established. At the beginning of 1995 and, in the case of each year thereafter, after the Administrator has made all deductions from the compliance account pursuant to § 73.35(b), the Administrator will record in the compliance account the allowances allocated to such units under § 73.10 or part 74 for the new 30th year.

* * * * *
[Amended]

8. Section 73.35 is amended as follows:

a. In paragraph (a) introductory text and paragraph (a)(1), replace the words “unit's” by the word “source's”;

b. In paragraph (a)(2)(i), replace the words “the unit's compliance subaccount” with the words “the compliance account of the source that includes the unit”;

c. In paragraph (a)(2)(ii), replace the words “the unit's compliance subaccount” with the words “the compliance account of the source that includes the unit” wherever they appear and remove the words “for the unit”, and replace the words “; or” with a period.

d. Remove paragraph (a)(2)(iii).

e. In paragraph (b)(1), add after the words “deduct allowances” the words “available for deduction under paragraph (a) of this section” and replace the words “each affected unit's compliance subaccount” with the words “each affected source's compliance account”;

f. In paragraph (b)(2), replace the words “allowances remain in the compliance subaccount” with the words “allowances available for deduction under paragraph (a) of this section remain in the compliance account”;

g. Remove paragraph (b)(3);

h. Revise paragraph (c)(1) to read as set forth below;

i. In paragraph (c)(2), replace the words “for the unit” with the words “for the units at the source”, replace the words “in its compliance subaccount.” by the words “in the source's compliance account.”, replace the words “from the compliance subaccount” by the words “from the compliance account”, and replace the words “unit's compliance subaccount” by the words “source's compliance account”;

j. In paragraph (d), replace the words “for each unit” by the words “for each source” and replace the word “unit's” by the word “source's”; and

k. Remove paragraph (e).

Compliance.
* * * * *

(c)(1) Identification of allowances by serial number. The authorized account representative for a source's compliance account may request that specific allowances, identified by serial number, in the compliance account be deducted for a calendar year in accordance with paragraph (b) or (d) of this section. Such request shall be submitted to the Administrator by the allowance transfer deadline for the year and include, in a format prescribed by the Administrator, the identification of the source and the appropriate serial numbers.

* * * * *
[Amended]

9. Section 73.36 is amended by:

a. In paragraph (a), replace the words “Unit accounts.” with the words “Compliance accounts.” and replace with words “compliance subaccount” Start Printed Page 32740with the words “compliance account” whenever they appear; and

b. In paragraph (b), replace the words “current year subaccount” with the words “general account” whenever they appear.

10. Section 73.37 is revised to read as follows:

Account error.

The Administrator may, at his or her sole discretion and on his or her own motion, correct any error in any Allowance Tracking System account. Within 10 business days of making such correction, the Administrator will notify the authorized account representative for the account.

[Amended]

11. Section 73.38 is amended as follows:

a. In paragraph (a), replace the words “delete the general account from the Allowance Tracking System.” by the words “close the general account.”; and

b. In paragraph (b), remove the words “and eliminated from the Allowance Tracking System” and the last sentence.

[Amended]

12. Section 73.50 is amended as follows:

a. In paragraph (a), remove the words “, including, but not limited to, transfers of an allowance to and from contemporaneous future year subaccounts, and transfers of an allowance to and from compliance subaccounts and current year subaccounts, and transfers of all allowances allocated for a unit for each calendar year in perpetuity”;

b. In paragraph (b)(1)(ii), remove the words “, or correct indication on the allowance transfer where a request involves the transfer of the unit's allowance in perpetuity”;

c. In paragraph (b)(2)(ii), remove the words “Allowance Tracking System” and “under 40 CFR part 73, or any other remedies” and remove the comma after the words “under State or Federal law”; and

d. Remove paragraph (b)(3).

[Removed and Reserved]

13. Section 73.51 is removed and reserved.

14. Section 73.52 is amended as follows revising paragraphs (a)(1), (a)(2) and (a)(3) and by removing paragraph (a)(4), and revising paragraph (b) and adding a new paragraph (c) to read as follows:

EPA recordation.

(a) * * *

(1) The transfer is corrected submitted under § 73.50;

(2) The transferor account includes each allowance identified by serial number in the transfer;

(3) If the allowances identified by serial number specified pursuant to § 73.50(b)(1)(ii) are subject to the limitation on transfer imposed pursuant to § 72.44(h)(1)(i) of this chapter, § 74.42 of this chapter, or § 74.47(c) of this chapter, the transfer is in accordance with such limitation.

(b) To the extent an allowance transfer submitted for recordation after the allowance transfer deadline includes allowances allocated for any year before the year of the allowance transfer deadline, the transfer of such allowance will not be recorded until after completion of the deductions pursuant to § 73.35(b) for year before the year of the allowance transfer deadline.

(c) Where an allowance transfer submitted for recordation fails to meet the requirements of paragraph (a) of this section, the Administrator will not record such transfer.

[Amended]

15. Section 73.70 is amended as follows:

a. In paragraph (f), replace the words “the subaccount” by the words “the Allowance Tracking System account”; and

b. In paragraph (i)(1), add, after the words “Allowance Tracking System account”, the words “of the source that includes”.

End Part Start Part

PART 74—SULFUR DIOXIDE OPTS-INS

1. The authority citation for part 74 continues to read as follows:

Start Authority

Authority: 42 U.S.C. 7601 and 7651, et seq.

End Authority
[Amended]

2. Section 74.18 is amended, in paragraph (d), remove the last sentence.

[Amended]

3. Section 74.40 is amended, in paragraph (a), add, after the words “an account”, the words “(unless the source that includes the opt-in unit already has a compliance account)” and remove the last sentence.

4. Section 74.42 is revised to read as follows:

Limitation on transfers.

(a) With regard to a transfer request submitted for recordation during the period starting January 1 and ending with the allowance transfer deadline in the same year, the Administrator will not record a transfer of an opt-in allowance that is allocated to an opt-in source for the year in which the transfer request is submitted or a subsequent year.

(b) With regard to a transfer request during the period starting with an allowance transfer deadline and ending December 31 in the same year, the Administrator will not record a transfer of an opt-in allowance that is allocated to an opt-in source for a year after the year in which the transfer request is submitted.

[Amended]

5. Section 74.43 is amended as follows:

a. In paragraph (a), remove the words “in lieu of any annual compliance certification report required under subpart I of part 72 of this chapter”;

b. In paragraph (b)(7), replace the word “At” by the words, “In an annual compliance certification report for a year during 1995 through 2004, at”; and

c. In paragraph (b)(8), replace the word “The” by the words, “In an annual compliance certification report for a year during 1995 through 2004, the”.

[Amended]

6. Section 74.44 is amended as follows:

a. In paragraphs (c)(2)(iii)(C), (c)(2)(iii)(D), (c)(2)(iii)(E) introductory text, and (c)(2)(iii)(E)(3), replace the words “opt-in source's compliance subaccount” by the words “compliance account of the source that includes the opt-in source” whenever they occur; and

b. In paragraph (c)(2)(iii)(F), replace the words “opt-in source's compliance subaccount” by the words “compliance account of the source that includes the opt-in source” and replace the words “source's compliance subaccount” by the words “compliance account of the source that includes the opt-in source”.

[Amended]

7. Section 74.6 is amended by removing and reserving paragraph (b)(2).

[Amended]

8. Section 74.47 is amended as follows:

a. In paragraph (c), replace the words “unit account” by the words “compliance account of the source that includes the replacement unit”; and

b. In paragraph (d)(2), add, after the words “Allowance Tracking System accounts”, the words “of the source that include the opt-in source and each replacement unit” and remove the words “for the opt-in source and for each replacement unit”.

[Amended]

9. Section 74.49 is amended, in paragraph (a), replace the words “an opt-in source's compliance subaccount” Start Printed Page 32741by the words “the compliance account of a source that include an opt-in source”.

[Amended]

10. Section 74.50 is amended as follows:

a. In paragraph (a)(2) introductory text, add, after the words “the account of the” the words “source that includes”;

b. In paragraph (a)(2)(i), replace the words “opt-in source's compliance subaccount” by the words “the compliance account of the source that includes the opt-in source”; and

c. In paragraph (b), replace the words “the opt-in source's unit account” by the words “the compliance account of the source that includes the opt-in source”; and

d. In paragraph (d), replace the words “an opt-in source does not hold” by the words “the source that include the opt-in source does not hold”.

End Part Start Part

PART 77—EXCESS EMISSIONS

1. The authority citation for part 77 continues to read as follows:

Start Authority

Authority: 42 U.S.C. 7601 and 7651, et seq.

End Authority
[Amended]

2. Section 77.3 is amended as follows:

a. In paragraph (a), replace the words “affected unit” by the words “affected source” and replace the word “unit's” by the word “source's”;

b. In paragraphs (b) and (c), replace the word “unit” by the word “source” wherever it appears; and

c. In paragraph (d) introductory text and paragraphs (d)(1), (d)(2), (d)(3), and (d)(5), replace the word “unit” by the word “source” wherever it appears, replace the word “unit's” by the word “source's” wherever it appears, and replace the words “compliance subaccount” by the words “compliance account”.

[Amended]

3. Section 77.4 is amended, in paragraphs (c)(1)(ii)(A), (d)(1), (d)(2), (d)(3), (g)(2)(ii), (g)(3)(ii), and (g)(3)(iii), by replacing the word “unit” by the word “source”.

[Amended]

4. Section 77.5 is amended by:

a. In paragraph (b), replace the words “compliance subaccount” with the words “compliance account”;

b. In paragraph (c), replace the words “, from the unit's compliance subaccount” with the words “allocated for the year after the year in which the source has excess emissions, from the source's compliance account” and replace the word “unit's” by the word “source's”; and

c. Remove paragraph (d).

[Amended]

5. Section 77.6 is amended by, in paragraph (a)(1), add, after the words “sulfur dioxide”, the words occur at the affected source” and add, after the words “owners and operators of”, the words “the affected source or”.

End Part Start Part

PART 78—APPEAL PROCEDURES FOR ACID RAIN PROGRAM

1. The authority citation for part 78 continues to read as follows:

Start Authority

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

End Authority
[Amended]

2. Section 78.1 is amended, in paragraph (a)(1), replace the words “parts 72, 73, 74, 75, 76, or 77 of this chapter or part 97 of this chapter” by the words “part 72, 73, 74, 75, 76, or 77 of this chapter, subparts AA through GG and subparts AAA and GGG of part 96 of this chapter, or part 97 of this chapter” and add new paragraphs (b)(7) and (b)(8) to read as follows:

Purpose and scope.

(b) * * *

(7) Under subparts AA through GG of part 96 of this chapter,

(i) The decision on the deduction of CAIR NOX allowances, and the adjustment of the information in a submission and the deduction or transfer of CAIR NOX allowances based on the information, as adjusted, under § 96.154;

(ii) The correction of an error in a CAIR NOX Allowance Tracking System account under § 97.156;

(iii) The decision on the transfer of CAIR NOX allowances under § 96.161;

(iv) The finalization of control period emissions data, including retroactive adjustment based on audit;

(v) The approval or disapproval of a petition under § 96.175.

(8) Under subparts AAA through GGG of part 96 of this chapter,

(i) The decision on the deduction of CAIR SO2 allowances, and the adjustment of the information in a submission and the deduction or transfer of CAIR SO2 allowances based on the information, as adjusted, under § 96.254;

(ii) The correction of an error in a CAIR SO2 Allowance Tracking System account under § 97.256;

(iii) The decision on the transfer of CAIR SO2 allowances under § 96.261;

(iv) The finalization of control period emissions data, including retroactive adjustment based on audit;

(v) The approval or disapproval of a petition under § 96.275.

[Amended]

3. Section 78.3 is amended by:

a. Amend paragraph (b)(3)(i) by adding, after the words “(unless the NOX authorized account representative is the petitioner)”, the words “or the CAIR designated representative or CAIR authorized account representative under paragraph (a)(5) or (a)(6) of this section (unless the CAIR designated representative or CAIR authorized account representative is the petitioner)”;

b. In paragraph (c)(7) replace the words “or part 97 of this chapter, as appropriate” by the words “, subparts AA through GG of part 96 of this chapter, subparts AAA through GGG of part 96 of this chapter, or part 97 of this chapter, as appropriate”;

c. In paragraph (d)(2) add, after the words “under the NOX Budget Trading Program”, the words “or on an account certificate of representation submitted by a CAIR designated representative or an application for a general account submitted by a CAIR authorized account representative under subparts AA through GG of part 96 of this chapter or subparts AAA through GGG of part 96 of this chapter,”;

d. Add new paragraphs (a)(5), (a)(6), and (d)(5) and (d)(6).

The additions and revisions read as follows:

Petition for administrative review and request for evidentiary hearing.

(a) * * *

(5) The following persons may petition for administrative review of a decision of the Administrator that is made under subparts AA through GG of part 96 and that is appealable under § 78.1(a) of this part:

(i) The CAIR designated representative for a source or the CAIR authorized account representative for any CAIR NOX Allowance Tracking System account covered by the decision; or

(ii) Any interested person.

(6) The following persons may petition for administrative review of a decision of the Administrator that is made under subparts AAA through GGG of part 96 and that is appealable under § 78.1(a) of this part:

(i) The CAIR designated representative for a source or the CAIR authorized account representative for any CAIR SO2 Allowance Tracking System account covered by the decision; or

(ii) Any interested person.

* * * * *
Start Printed Page 32742

(d) * * *

(5) Any provision or requirement of subparts AA through GG of part 96, including the standard requirements under § 96.106 of this chapter and any emission monitoring or reporting requirements.

(6) Any provision or requirement of subparts AAA through GGG of part 96, including the standard requirements under § 96.206 of this chapter and any emission monitoring or reporting requirements.

* * * * *
[Amended]

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

Filings.

(a) * * * Any filings on behalf of owners and operators of a CAIR unit or source shall be signed by the CAIR designated representative. Any filings on behalf of persons with an interest in CAIR NOX or SO2 allowances in a general account shall be signed by the CAIR authorized account representative. * * *

* * * * *
[Amended]

5. Section 78.12 is amended, in paragraph (a)(2), by adding, after the words “a NOX Budget permit”, the words ”, CAIR permit,”.

End Part Start Part

PART 96—[AMENDED]

1. Authority citation for Part 96 continues to read as follows:

Start Authority

Authority: 42 U.S.C. 7401, 7403, 7410, 7601. 2. Part 96 is amended by adding subparts AA through CC, adding and reserving subpart DD and adding subparts EE through HH to read as follows:

End Authority

Subpart AA—CAIR NOX Trading Program General Provisions

96.101
Purpose.
96.102
Definitions.
96.103
Measurements, abbreviations, and acronyms.
96.104
Applicability.
96.105
Retired unit exemption.
96.106
Standard requirements.
96.107
Computation of time.
96.108
Appeal Procedures.
Subpart BB—CAIR Designated Representative for CAIR Sources
96.110
Authorization and responsibilities of CAIR designated representative.
96.111
Alternate CAIR designated representative.
96.112
Changing CAIR designated representative and alternate CAIR designated representative; changes in owners and operators.
96.113
Certificate of representation.
96.114
Objections concerning CAIR designated representative.
Subpart CC—Permits
96.120
General CAIR NOX Trading Program permit requirements.
96.121
Submission of CAIR permit applications.
96.122
Information requirements for CAIR permit applications.
96.123
CAIR permit contents and term.
96.124
CAIR permit revisions.
Subpart DD—[Reserved] Subpart EE—CAIR NOX Allowance Allocations
96.140
State trading budgets.
96.141
Timing requirements for CAIR NOX allowance allocations.
96.142
CAIR NOX allowance allocations.
Subpart FF—CAIR NOX Allowance Tracking System
96.150
CAIR NOX Allowance Tracking System accounts.
96.151
Establishment of accounts.
96.152
Responsibilities of CAIR NOX authorized account representative.
96.153
Recordation of CAIR NOX allowance allocations.
96.154
Compliance with CAIR NOX emissions limitation.
96.155
Banking.
96.156
Account error.
96.157
Closing of general accounts.
Subpart GG—CAIR NOX Allowance Transfers
96.160
Submission of CAIR NOX allowance transfers.
96.161
EPA recordation.
96.162
Notification.
Subpart HH—Monitoring and Reporting
96.170
General requirements.
96.171
Initial certification and recertification procedures.
96.172
Out of control periods.
96.173
Notifications.
96.174
Recordkeeping and reporting.
96.175
Petitions.
96.176
Additional requirements to provide heat input data.

Subpart AA—CAIR NOX Trading Program General Provisions

Purpose.

This subpart establishes the model rule comprising general provisions and the applicability, permitting, allowance, excess emissions, and monitoring for the state Clean Air Interstate Rule (CAIR) NOX Trading Program, under section 110 of the Clean Air Act (CAA) and § 51.123 of this chapter, as a means of reducing national NOX emissions.

Definitions.

The terms used in this subpart shall have the meanings set forth in this section as follows:

Account number means the identification number given by the Administrator to each CAIR NOX Allowance Tracking System account.

Acid Rain emissions limitation means a limitation on emissions of sulfur dioxide or nitrogen oxides under the Acid Rain Program.

Acid Rain Program means a multi-state sulfur dioxide and nitrogen oxides air pollution control and emission reduction program established by the Administrator under title IV of the CAA and parts 72 through 78 of this chapter.

Administrator means the Administrator of the United States Environmental Protection Agency or the Administrator's duly authorized representative.

Allocate or allocation means, with regard to CAIR NOX allowances, the determination by the Administrator of the amount of CAIR NOX allowances to be initially credited to a CAIR unit or a new unit set-aside.

Alternate CAIR designated representative means, for a CAIR source and each CAIR unit at the source, the natural person who is authorized by the owners and operators of the source and all CAIR units at the source in accordance with subpart BB of this part, to act on behalf of the CAIR designated representative in matters pertaining to the CAIR SO2 Trading Program and the CAIR NOX Trading Program. This natural person shall be the same person as the alternate designated representative under the Acid Rain Program under § 72.22 of this chapter.

Automated data acquisition and handling system or DAHS means that component of the CEMS, or other emissions monitoring system approved for use under subpart HH of this part, designed to interpret and convert individual output signals from pollutant concentration monitors, flow monitors, diluent gas monitors, and other component parts of the monitoring system to produce a continuous record of the measured parameters in the measurement units required by subpart HH of this part.

Boiler means an enclosed fossil- or other-fuel-fired combustion device used to produce heat and to transfer heat to recirculating water, steam, or other medium.

Bottoming-cycle cogeneration unit means a cogeneration unit in which the energy input to the unit is first used to produce useful thermal energy and at least some of the reject heat from the useful thermal energy application or Start Printed Page 32743process is then used for power production.

CAIR designated representative means, for a CAIR source and each CAIR unit at the source, the natural person who is authorized by the owners and operators of the source and all CAIR units at the source, in accordance with subpart BB of this part, to represent and legally bind each owner and operator in matters pertaining to the CAIR SO2 Trading Program and to the CAIR NOX Trading Program. This natural person shall be the same person who is the authorized account representative under the Acid Rain Program under § 72.20 of this chapter.

CAIR NOXallowance means a limited authorization issued by the Administrator to emit up to one ton of nitrogen oxide during the control period of the specified year or of any year thereafter under the CAIR NOX Program or, except for purposes of subpart EE of this part, any NOX SIP Call allowance, allocated for the 2009, or any earlier, ozone season that is not used to meet an NOX emissions limitation under the NOX Budget Trading Program.

CAIR NOXallowance deduction or deduct CAIR NOXallowances means the permanent withdrawal of CAIR NOX allowances by the Administrator from a compliance account in order to account for a specified number of tons of nitrogen oxide emissions from all CAIR units at a CAIR source for a control period, determined in accordance with subparts FF and HH of this part, or to account for excess emissions.

CAIR NOXAllowance Tracking System (INATS) means the system by which the Administrator records allocations, deductions, and transfers of CAIR NOX allowances under the CAIR NOX Trading Program.

CAIR NOXAllowance Tracking System account means an account in the CAIR NOX Allowance Tracking System established by the Administrator for purposes of recording the allocation, holding, transferring, or deducting of CAIR NOX allowances.

CAIR NOXallowance transfer deadline means midnight of March 1 or, if March 1 is not a business day, midnight of the first business day thereafter and is the deadline by which a CAIR NOX allowance transfer must be submitted for recordation in a CAIR source's compliance account in order to meet the source's CAIR NOX emissions limitation for the control period immediately preceding such deadline.

CAIR NOXallowances held or hold CAIR NOXallowances means the CAIR NOX allowances recorded by the Administrator, or submitted to the Administrator for recordation, in accordance with subparts FF and GG of this part, in a CAIR NOX Allowance Tracking System account.

CAIR NOXauthorized account representative means a responsible natural person who is authorized, in accordance with subpart BB of this part, to transfer and otherwise dispose of CAIR NOX allowances held in a CAIR NOX Allowance Tracking System general account; or, in the case of a compliance account, the CAIR designated representative of the source.

CAIR NOXemissions limitation means, for a CAIR source, the tonnage equivalent of the CAIR NOX allowances available for compliance deduction for the source under §§ 96.154(a) and (b) in a control period.

CAIR NOXTrading Program means a multi-state nitrogen oxides air pollution control and emission reduction program established by the Administrator in accordance with subparts AA through HH of this part and § 51.123 of this chapter, as a means of mitigating interstate transport of fine particulates, ozone, and nitrogen oxides.

CAIR permit means the legally binding and federally enforceable written document, or portion of such document, issued by the permitting authority under subpart CC of this part, including any permit revisions, specifying the CAIR SO2 and NOX Trading Program requirements applicable to a CAIR source, to each CAIR unit at the CAIR source, and to the owners and operators and the CAIR designated representative of the CAIR source and each CAIR unit.

CAIR SO2Trading Program means a multi-state sulfur dioxide air pollution control and emission reduction program established by the Administrator in accordance with subparts AAA through HHH of this part and § 51.124 of this chapter, as a means of mitigating interstate transport of fine particulates.

CAIR source means a source that includes one or more CAIR units.

CAIR unit means a unit that is subject to the CAIR NOX Trading Program under § 96.104.

Clean Air Act means the Clean Air Act, 42 U.S.C. 7401, et seq.

Coal means any solid fuel classified as anthracite, bituminous, subbituminous, or lignite.

Coal-derived fuel means any fuel (whether in a solid, liquid, or gaseous state) produced by the mechanical, thermal, or chemical processing of coal.

Coal-fired means, with regard to a unit, combusting coal or any coal-derived fuel alone or in combination with any amount of any other fuel in any year.

Cogeneration unit means a unit:

(1) Having equipment used to produce electricity and useful thermal energy for industrial, commercial, heating, or cooling purposes through the sequential use of energy; and

(2) Producing during the 12-month period starting on the date the unit first produces electricity and during any calendar year after which the unit first produces electricity—

(i) For a topping-cycle cogeneration unit,

(A) Useful thermal energy not less than 5 percent of total energy output; and

(B) Useful power that, when added to one-half of useful thermal energy produced, is not less then 42.5 percent of total energy input or, if useful thermal energy produced is less than 15 percent of total energy output, not less than 45 percent of total energy input.

(ii) For a bottoming-cycle cogeneration unit, useful power not less than 45 percent of total energy input.

Combustion turbine means an enclosed device comprising a compressor, a combustor, and a turbine and in which the flue gas resulting from the combustion of fuel in the combustor passes through the turbine, rotating the turbine. A combustion turbine that is combined cycle also includes any associated heat recovery steam generator and steam turbine.

Commence commercial operation means, with regard to a unit that serves a generator, to have begun to produce steam, gas, or other heated medium used to generate electricity for sale or use, including test generation. Except as provided in § 96.105, for a unit that is a CAIR unit under § 96.104 on the date the unit commences commercial operation, such date shall remain the unit's date of commencement of commercial operation even if the unit is subsequently modified or reconstructed. Except as provided in § 96.105, for a unit that is not a CAIR unit under § 96.104 on the date the unit commences commercial operation, the date the unit becomes a CAIR unit under § 96.104 shall be the unit's date of commencement of commercial operation.

Commence operation means to have begun any mechanical, chemical, or electronic process, including, with regard to a unit, start-up of a unit's combustion chamber. Except as provided in § 96.105, for a unit that is a CAIR unit under § 96.104 on the date of commencement of operation, such date shall remain the unit's date of commencement of operation even if the unit is subsequently modified or reconstructed. Except as provided in § 96.105, for a unit that is not a CAIR Start Printed Page 32744unit under § 96.104 on the date of commencement of operation, the date the unit becomes a CAIR unit under § 96.104 shall be the unit's date of commencement of operation.

Common stack means a single flue through which emissions from two or more units are exhausted.

Compliance account means a CAIR NOX Allowance Tracking System account, established by the Administrator for a CAIR source under subpart FF of this part, in which the CAIR NOX allowance allocations for the CAIR units at the source are initially recorded and in which are held CAIR NOX allowances available for use for a control period in order to meet the source's CAIR NOX emissions limitation.

Continuous emission monitoring system or CEMS means the equipment required under subpart HH of this part to sample, analyze, measure, and provide, by means of readings recorded at least once every 15 minutes (using an automated data acquisition and handling system (DAHS)), a permanent record of nitrogen oxide (NOX) emissions, stack gas volumetric flow rate or stack gas moisture content (as applicable), in a manner consistent with part 75 of this chapter. The following systems are the principal types of continuous emission monitoring systems required under subpart HH of this part:

(1) A flow monitoring system, consisting of a stack flow rate monitor and an automated DAHS. A flow monitoring system provides a permanent, continuous record of stack gas volumetric flow rate, in standard cubic feet per hour (scfh);

(2) A nitrogen oxides (NOX) concentration monitoring system, consisting of a NOX pollutant concentration monitor and an automated DAHS. A NOX concentration monitoring system provides a permanent, continuous record of NOX emissions, in parts per million (ppm);

(3) A nitrogen oxides emission rate (or NOX-diluent) monitoring system, consisting of a NOX pollutant concentration monitor, a diluent gas (CO2 or O2) monitor, and an automated DAHS. A NOX-diluent monitoring system provides a permanent, continuous record of: NOX concentration, in parts per million (ppm); diluent gas concentration, in percent CO2 or O2 (percent CO2 or O2); and NOX emission rate, in pounds per million British thermal units (lb/mmBtu);

(4) A moisture monitoring system, as defined in § 75.11(b)(2) of this chapter. A moisture monitoring system provides a permanent, continuous record of the stack gas moisture content, in percent H2 O (percent H2 O);

(5) A carbon dioxide (CO2) monitoring system, consisting of a CO2 pollutant concentration monitor (or an oxygen monitor plus suitable mathematical equations from which the CO2 concentration is derived) and the automated DAHS. A carbon dioxide monitoring system provides a permanent, continuous record of CO2 emissions, in percent CO2 (percent CO2); and

(6) An oxygen (O2) monitoring system, consisting of an O2 concentration monitor and an automated DAHS. An O2 monitoring system provides a permanent, continuous record of O2 in percent O2 (percent O2).

Control period means the period beginning January 1 of a year and ending on December 31 of the same year, inclusive.

Emissions means air pollutants exhausted from a unit or source into the atmosphere, as measured, recorded, and reported to the Administrator by the CAIR designated representative and as determined by the Administrator in accordance with subpart HH of this part.

Energy Information Administration means the Energy Information Administration of the United States Department of Energy.

Excess emissions means any ton of nitrogen oxide emitted by the CAIR units at a CAIR source during a control period that exceeds the CAIR NOX emissions limitation for the source.

Fossil fuel means natural gas, petroleum, coal, or any form of solid, liquid, or gaseous fuel derived from such material.

Fossil-fuel-fired means, with regard to a unit, any boiler or turbine combusting any amount of fossil fuel.

General account means a CAIR NOX Allowance Tracking System account, established under subpart FF of this part, that is not a compliance account.

Generator means a device that produces electricity.

Gross thermal energy means, with regard to a cogeneration unit, useful thermal energy output plus, where such output is made available for an industrial or commercial process, any heat contained in condensate return or makeup water.

Heat input means, with regard to a specified period to time, the product (in mmBtu/time) of the gross calorific value of the fuel (in Btu/lb) divided by 1,000,000 Btu/mmBtu and multiplied by the fuel feed rate into a combustion device (in lb of fuel/time), as measured, recorded, and reported to the Administrator by the CAIR designated representative and as determined by the Administrator in accordance with subpart HH of this part. Heat input does not include the heat derived from preheated combustion air, recirculated flue gases, or exhaust from other sources.

Heat input rate means the amount of heat input (in mmBtu) divided by unit operating time (in hr) or, with regard to a specific fuel, the amount of heat input attributed to the fuel (in mmBtu) divided by the unit operating time (in hr) during which the unit combusts the fuel.

Life-of-the-unit, firm power contractual arrangement means a unit participation power sales agreement under which a customer reserves, or is entitled to receive, a specified amount or percentage of nameplate capacity and associated energy from any specified unit and pays its proportional amount of such unit's total costs, pursuant to a contract:

(1) For the life of the unit;

(2) For a cumulative term of no less than 30 years, including contracts that permit an election for early termination; or

(3) For a period no less than 25 years or 70 percent of the economic useful life of the unit determined as of the time the unit is built, with option rights to purchase or release some portion of the nameplate capacity and associated energy generated by the unit at the end of the period.

Maximum design heat input means the maximum amount of fuel per hour (in Btu/hr) that a unit is capable of combusting on a steady state basis, as specified by the manufacturer of the unit as of the initial installation of the unit.

Monitoring system means any monitoring system that meets the requirements of subpart HH of this part, including a continuous emissions monitoring system or an alternative monitoring system.

Nameplate capacity means the maximum electrical generating output (in MWe) that a generator can sustain over a specified period of time when not restricted by seasonal or other deratings as specified by the manufacturer of the generator as of the initial installation of the generator or, if the generator is subsequently modified or reconstructed resulting in an increase in such maximum electrical generating output, as specified by the person conducting the modification or reconstruction.

NOXBudget Trading Program means a multi-state nitrogen oxide air pollution control and emission reduction program established by air pollution control and emission Start Printed Page 32745reduction program established by the Administrator in accordance with subparts A through I of this part and § 51.121 of this chapter, as a means of mitigating interstate transport of ozone and nitrogen oxides.

NOXSIP Call allowance means a limited authorization issued by the Administrator under the NOX Budget Trading Program to emit up to one ton of nitrogen oxides during the ozone season of the specified year or any year thereafter under the NOX Budget Trading Program or during the control period in 2010 or any year thereafter under the CAIR NOX Trading Program, provided that § 96.54(f) of this chapter shall not apply to the use of such allowance under § 96.154.

Operator means any person who operates, controls, or supervises a CAIR unit or a CAIR source and shall include, but not be limited to, any holding company, utility system, or plant manager of such a unit or source.

Owner means any of the following persons:

(1) Any holder of any portion of the legal or equitable title in a CAIR unit; or

(2) Any holder of a leasehold interest in a CAIR unit; or

(3) Any purchaser of power from a CAIR unit under a life-of-the-unit, firm power contractual arrangement; provided that, unless expressly provided for in a leasehold agreement, owner shall not include a passive lessor, or a person who has an equitable interest through such lessor, whose rental payments are not based (either directly or indirectly) on the revenues or income from the CAIR unit; or

(4) With regard to any general account, any person who has an ownership interest with respect to the CAIR NOX allowances held in the general account and who is subject to the binding agreement for the CAIR authorized account representative to represent that person's ownership interest with respect to CAIR NOX allowances.

Permitting authority means the State air pollution control agency, local agency, other State agency, or other agency authorized by the Administrator to issue or revise permits to meet the requirements of the CAIR NOX Trading Program in accordance with subpart CC of this part.

Potential electrical output capacity means 33 percent of a unit's maximum design heat input, divided by 3,413 mmBtu/kWh, divided by 1,000 kWh/MWh, and multiplied by 8,760 hr/yr.

Receive or receipt of means, when referring to the permitting authority or the Administrator, to come into possession of a document, information, or correspondence (whether sent in hard copy or by authorized electronic transmission), as indicated in an official correspondence log, or by a notation made on the document, information, or correspondence, by the permitting authority or the Administrator in the regular course of business.

Recordation, record, or recorded means, with regard to CAIR NOX allowances, the movement of CAIR NOX allowances by the Administrator into or between CAIR NOX Allowance Tracking System accounts, for purposes of allocation, transfer, or deduction.

Reference method means any direct test method of sampling and analyzing for an air pollutant as specified in § 75.22 of this chapter.

Serial number means for a CAIR NOX allowance, the unique identification number assigned to each CAIR NOX allowance by the Administrator, under § 96.153(f).

Sequential use of energy means:

(1) For a topping-cycle cogeneration unit, the use of reject heat from power production in a useful thermal energy application or process; or

(2) For a bottoming-cycle cogeneration unit, the use of reject heat from useful thermal energy application or process in power production.

Source means all buildings, structures, or installations located in one or more contiguous or adjacent properties under common control of the same person or persons. For purposes of section 502(c) of the Clean Air Act, a “source,” including a “source” with multiple units, shall be considered a single “facility.”

State means one of the 50 States or the District of Columbia that adopts the CAIR NOX Trading Program pursuant to § 51.123 of this chapter.

Submit or serve means to send or transmit a document, information, or correspondence to the person specified in accordance with the applicable regulation:

(1) In person;

(2) By United States Postal Service; or

(3) By other means of dispatch or transmission and delivery. Compliance with any “submission,” “service,” or “mailing” deadline shall be determined by the date of dispatch, transmission, or mailing and not the date of receipt.

Title V operating permit means a permit issued under title V of the Clean Air Act and part 70 or part 71 of this chapter.

Title V operating permit regulations means the regulations that the Administrator has approved or issued as meeting the requirements of title V of the Clean Air Act and part 70 or 71 of this chapter.

Ton means 2,000 pounds. For the purpose of determining compliance with the CAIR NOX emissions limitation, total tons of nitrogen oxides emissions for a control period shall be calculated as the sum of all recorded hourly emissions (or the mass equivalent of the recorded hourly emission rates) in accordance with subpart HH of this part, with any remaining fraction of a ton equal to or greater than 0.50 tons deemed to equal one ton and any remaining fraction of a ton less than 0.50 tons deemed to equal zero tons.

Topping-cycle cogeneration unit means a cogeneration unit in which the energy input to the unit is first used to produce useful power and at least some of the reject heat from the power production is then used to provide useful thermal energy.

Total energy input means, with regard to a cogeneration unit, total energy of all forms supplied to the cogeneration unit, excluding energy produced by the cogeneration unit itself.

Total energy output means, with regard to a cogeneration unit, the sum of useful power and useful thermal energy produced by the cogeneration unit.

Unit means a stationary boiler or combustion turbine.

Unit operating day means a calendar day in which a unit combusts any fuel.

Unit operating hour or hour of unit operation means an hour in which a unit combusts any fuel. Useful power means, with regard to a cogeneration unit, electricity or mechanical energy made available for use, excluding any such energy used in the power production process (which process includes, but is not limited to, any on-site processing or treatment of fuel combusted at the unit and any on-site emission controls).

Useful thermal energy means, with regard to a cogeneration unit, thermal energy that is:

(1) Made available to an industrial or commercial process, excluding any heat contained in condensate return or makeup water;

(2) Used in a heat application (e.g., space heating or domestic hot water heating); or

(3) Used in a space cooling application (i.e., thermal energy used by an absorption chiller).

Utility power distribution system means the portion of an electricity grid owned or operated by a distribution utility and dedicated to delivering electricity to customers.

Start Printed Page 32746
Measurements, abbreviations, and acronyms.

Measurements, abbreviations, and acronyms used in this part are defined as follows:

Btu—British thermal unit.

CO2—carbon dioxide.

NOX—nitrogen oxide.

hr—hour.

kW—kilowatt electrical.

kWh—kilowatt hour.

mmBtu—million Btu.

MWe—megawatt electrical.

MWh—megawatt hour.

O2—oxygen.

SO2—sulfur dioxide.

yr—year.

Applicability.

The following units in a State shall be CAIR units, and any source that includes one or more such units shall be a CAIR source, subject to the requirements of this subpart and subparts BB through HH of this part:

(a) Except a unit under paragraph (b) of this section, a fossil fuel-fired boiler or combustion turbine serving at any time a generator with nameplate capacity of more than 25 MWe producing electricity for sale.

(b) A fossil fuel-fired cogeneration unit serving at any time a generator with nameplate capacity of more than 25 MWe and in any year supplying more than one-third of the unit's potential electric output capacity or 219,000 MWh, whichever is greater, to any utility power distribution system for sale.

Retired unit exemption.

(a) This section applies to any CAIR unit that is permanently retired.

(b)(1) Any CAIR unit that is permanently retired shall be exempt from the CAIR NOX Trading Program, except for the provisions of this section, § 96.102, § 96.103, § 96.104, § 96.106(c)(5) through (8), § 96.107, and subparts EE through GG of this part.

(2) The exemption under paragraph (b)(1) of this section shall become effective the day on which the unit is permanently retired. Within 30 days of permanent retirement, the CAIR designated representative shall submit a statement to the permitting authority otherwise responsible for administering any CAIR permit for the unit. The CAIR designated representative shall submit a copy of the statement to the Administrator. The statement shall state, in a format prescribed by the permitting authority, that the unit was permanently retired on a specific date, and will comply with the requirements of paragraph (c) of this section.

(3) After receipt of the notice under paragraph (b)(2) of this section, the permitting authority will amend any permit under subpart CC of this part covering the source at which the unit is located to add the provisions and requirements of the exemption under paragraphs (b)(1) and (c) of this section.

(c) Special provisions.

(1) A unit exempt under this section shall not emit any nitrogen oxides, starting on the date that the exemption takes effect.

(2) The permitting authority will allocate CAIR NOX allowances under subpart EE of this part to a unit exempt under this section.

(3) For a period of 5 years from the date the records are created, the owners and operators of a unit exempt under this section shall retain at the source that includes the unit, records demonstrating that the unit is permanently retired. The 5-year period for keeping records may be extended for cause, at any time prior to the end of the period, in writing by the permitting authority or the Administrator. The owners and operators bear the burden of proof that the unit is permanently retired.

(4) The owners and operators and, to the extent applicable, the CAIR designated representative of a unit exempt under this section shall comply with the requirements of the CAIR NOX Trading Program concerning all periods for which the exemption is not in effect, even if such requirements arise, or must be complied with, after the exemption takes effect.

(5) A unit exempt under this section and located at a source that is required, or but for this exemption would be required, to have a title V operating permit shall not resume operation unless the CAIR designated representative of the source submits a complete CAIR permit application under § 96.122 for the unit not less than 18 months (or such lesser time provided by the permitting authority) before the later of January 1, 2010 or the date on which the unit resumes operation.

(6) On the earlier of the following dates, a unit exempt under paragraph (b) of this section shall lose its exemption:

(i) The date on which the CAIR designated representative submits a CAIR permit application for the unit under paragraph (c)(5) of this section;

(ii) The date on which the CAIR designated representative is required under paragraph (c)(5) of this section to submit a CAIR permit application for the unit; or

(iii) The date on which the unit resumes operation, if the CAIR designated representative is not required to submit a CAIR permit application for the unit.

(7) For the purpose of applying monitoring requirements under subpart HH of this part, a unit that loses its exemption under this section shall be treated as a unit that commences operation and commercial operation on the first date on which the unit resumes operation.

Standard requirements.

(a) Permit Requirements.

(1) The CAIR designated representative of each CAIR source required to have a title V operating permit and each CAIR unit required to have a title V operating permit at the source shall:

(i) Submit to the permitting authority a complete CAIR permit application under § 96.122 in accordance with the deadlines specified in § 96.121(b) and (c); and

(ii) Submit in a timely manner any supplemental information that the permitting authority determines is necessary in order to review a CAIR permit application and issue or deny a CAIR permit.

(2) The owners and operators of each CAIR source required to have a title V operating permit and each CAIR unit required to have a title V operating permit at the source shall have a CAIR permit issued by the permitting authority and operate the unit in compliance with such CAIR permit.

(3) The owners and operators of a CAIR source that is not otherwise required to have a title V operating permit are not required to submit a CAIR permit application, and to have a CAIR permit, under subpart CC of this part for such CAIR source.

(b) Monitoring requirements.

(1) The owners and operators and, to the extent applicable, the CAIR designated representative of each CAIR source and each CAIR unit at the source shall comply with the monitoring requirements of subpart HH of this part.

(2) The emissions measurements recorded and reported in accordance with subpart HH of this part shall be used to determine compliance by the unit with the CAIR NOX emissions limitation under paragraph (c) of this section.

(c) Nitrogen oxide emission requirements.

(1) As of the CAIR NOX allowance transfer deadline for a control period, the owners and operators of each CAIR source and each CAIR unit at the source shall hold, in the source's compliance account, CAIR NOX allowances available for compliance deductions for the control period under § 96.154(a) in an amount not less than the total nitrogen oxides emissions for the Start Printed Page 32747control period from all CAIR units at the source, as determined in accordance with subpart HH of this part.

(2) Each ton of nitrogen oxide emitted in excess of the CAIR NOX emissions limitation shall constitute a separate violation of this subpart, the Clean Air Act, and applicable State law.

(3) A CAIR unit shall be subject to the requirements under paragraph (c)(1) of this section starting on the later of January 1, 2010 or the deadline for meeting the unit's monitor certification requirements under § 96.170(b)(1) or (b)(2).

(4) A CAIR NOX allowance shall not be deducted, in order to comply with the requirements under paragraph (c)(1) of this section, for a control period in a year prior to the year for which the CAIR NOX allowance was allocated.

(5) CAIR NOX allowances shall be held in, deducted from, or transferred into or among CAIR NOX Allowance Tracking System accounts in accordance with subpart EE of this part.

(6) A CAIR NOX allowance is a limited authorization to emit one ton of nitrogen oxide in accordance with the CAIR NOX Trading Program. No provision of the CAIR NOX Trading Program, the CAIR permit application, the CAIR permit, or exemption under § 96.105 and no provision of law shall be construed to limit the authority of the State or the United States to terminate or limit such authorization.

(7) A CAIR NOX allowance does not constitute a property right.

(8) Upon recordation by the Administrator under subparts FF and GG of this part, every allocation, transfer, or deduction of a CAIR NOX allowance to or from a CAIR unit's compliance account is incorporated automatically in any CAIR permit of the CAIR unit.

(d) Excess emissions requirements.

(1) The owners and operators of a CAIR unit that has excess emissions in any control period shall:

(i) Surrender the CAIR NOX allowances required for deduction under § 96.154(d)(1); and

(ii) Pay any fine, penalty, or assessment or comply with any other remedy imposed under § 96.154(d)(2).

(e) Recordkeeping and Reporting Requirements.

(1) Unless otherwise provided, the owners and operators of the CAIR source and each CAIR unit at the source shall keep on site at the source each of the following documents for a period of 5 years from the date the document is created. This period may be extended for cause, at any time prior to the end of 5 years, in writing by the permitting authority or the Administrator.

(i) The certificate of representation under § 96.113 for the CAIR designated representative for the source and each CAIR unit at the source and all documents that demonstrate the truth of the statements in the certificate of representation; provided that the certificate and documents shall be retained on site at the source beyond such 5-year period until such documents are superseded because of the submission of a new certificate of representation under § 96.113 changing the CAIR designated representative.

(ii) All emissions monitoring information, in accordance with subpart HH of this part; provided that to the extent that subpart HH of this part provides for a 3-year period for recordkeeping, the 3-year period shall apply.

(iii) Copies of all reports, compliance certifications, and other submissions and all records made or required under the CAIR NOX Trading Program.

(iv) Copies of all documents used to complete a CAIR permit application and any other submission under the CAIR NOX Trading Program or to demonstrate compliance with the requirements of the CAIR NOX Trading Program.

(2) The CAIR designated representative of a CAIR source and each CAIR unit at the source shall submit the reports required under the CAIR NOX Trading Program, including those under subpart HH of this part.

(f) Liability.

(1) Any person who knowingly violates any requirement or prohibition of the CAIR NOX Trading Program, a CAIR permit, or an exemption under § 96.105 shall be subject to enforcement pursuant to applicable State or Federal law.

(2) Any person who knowingly makes a false material statement in any record, submission, or report under the CAIR NOX Trading Program shall be subject to criminal enforcement pursuant to the applicable State or Federal law.

(3) No permit revision shall excuse any violation of the requirements of the CAIR NOX Trading Program that occurs prior to the date that the revision takes effect.

(4) Each CAIR source and each CAIR unit shall meet the requirements of the CAIR NOX Trading Program.

(5) Any provision of the CAIR NOX Trading Program that applies to a CAIR source or the CAIR designated representative of a CAIR source shall also apply to the owners and operators of such source and of the CAIR units at the source.

(6) Any provision of the CAIR NOX Trading Program that applies to a CAIR unit or the CAIR designated representative of a CAIR unit shall also apply to the owners and operators of such unit.

(g) Effect on Other Authorities. No provision of the CAIR NOX Trading Program, a CAIR permit application, a CAIR permit, or an exemption under § 96.105 shall be construed as exempting or excluding the owners and operators and, to the extent applicable, the CAIR designated representative of a CAIR source or CAIR unit from compliance with any other provision of the applicable, approved State implementation plan, a federally enforceable permit, or the Clean Air Act.

Computation of time.

(a) Unless otherwise stated, any time period scheduled, under the CAIR NOX Trading Program, to begin on the occurrence of an act or event shall begin on the day the act or event occurs.

(b) Unless otherwise stated, any time period scheduled, under the CAIR NOX Trading Program, to begin before the occurrence of an act or event shall be computed so that the period ends the day before the act or event occurs.

(c) Unless otherwise stated, if the final day of any time period, under the CAIR NOX Trading Program, falls on a weekend or a State or Federal holiday, the time period shall be extended to the next business day.

Appeal Procedures.

The appeal procedures for decisions of the Administrator under the CAIR NOX Trading Program are set forth in part 78 of this chapter.

Subpart BB—CAIR Designated Representative for CAIR Sources

Authorization and responsibilities of CAIR designated representative.

(a) Except as provided under § 96.111, each CAIR source, including all CAIR units at the source, shall have one and only one CAIR designated representative, with regard to all matters under the CAIR NOX Trading Program concerning the source or any CAIR unit at the source.

(b) The CAIR designated representative of the CAIR source shall be selected by an agreement binding on the owners and operators of the source and all CAIR units at the source and shall act in accordance with the certification statement in § 96.113(a)(5)(iv).

(c) Upon receipt by the Administrator of a complete certificate of representation under § 96.113, the CAIR designated representative of the source shall represent and, by his or her representations, actions, inactions, or submissions, legally bind each owner Start Printed Page 32748and operator of the CAIR source represented and each CAIR unit at the source in all matters pertaining to the CAIR NOX Trading Program, notwithstanding any agreement between the CAIR designated representative and such owners and operators. The owners and operators shall be bound by any decision or order issued to the CAIR designated representative by the permitting authority, the Administrator, or a court regarding the source or unit.

(d) No CAIR permit will be issued, no emissions data reports will be accepted, and no CAIR NOX Allowance Tracking System account will be established for a CAIR unit at a source, until the Administrator has received a complete certificate of representation under § 96.113 for a CAIR designated representative of the source and the CAIR units at the source.

(e)(1) Each submission under the CAIR NOX Trading Program shall be submitted, signed, and certified by the CAIR designated representative for each CAIR source on behalf of which the submission is made. Each such submission shall include the following certification statement by the CAIR designated representative: “I am authorized to make this submission on behalf of the owners and operators of the source or units for which the submission is made. I certify under penalty of law that I have personally examined, and am familiar with, the statements and information submitted in this document and all its attachments. Based on my inquiry of those individuals with primary responsibility for obtaining the information, I certify that the statements and information are to the best of my knowledge and belief true, accurate, and complete. I am aware that there are significant penalties for submitting false statements and information or omitting required statements and information, including the possibility of fine or imprisonment.”

(2) The permitting authority and the Administrator will accept or act on a submission made on behalf of owner or operators of a CAIR source or a CAIR unit only if the submission has been made, signed, and certified in accordance with paragraph (e)(1) of this section.

Alternate CAIR designated representative.

(a) A certificate of representation may designate one and only one alternate CAIR designated representative, who may act on behalf of the CAIR designated representative. The agreement by which the alternate CAIR designated representative is selected shall include a procedure for authorizing the alternate CAIR designated representative to act in lieu of the CAIR designated representative.

(b) Upon receipt by the Administrator of a complete certificate of representation under § 96.113, any representation, action, inaction, or submission by the alternate CAIR designated representative shall be deemed to be a representation, action, inaction, or submission by the CAIR designated representative.

(c) Except in this section and §§ 96.102, 96.110(a), 96.112, 96.113, and 96.151, whenever the term “CAIR designated representative” is used in this subpart, the term shall be construed to include the alternate CAIR designated representative.

Changing CAIR designated representative and alternate CAIR designated representative; changes in owners and operators.

(a) Changing CAIR designated representative. The CAIR designated representative may be changed at any time upon receipt by the Administrator of a superseding complete certificate of representation under § 96.113. Notwithstanding any such change, all representations, actions, inactions, and submissions by the previous CAIR designated representative prior to the time and date when the Administrator receives the superseding certificate of representation shall be binding on the new CAIR designated representative and the owners and operators of the CAIR source and the CAIR units at the source.

(b) Changing alternate CAIR designated representative. The alternate CAIR designated representative may be changed at any time upon receipt by the Administrator of a superseding complete certificate of representation under § 96.113. Notwithstanding any such change, all representations, actions, inactions, and submissions by the previous alternate CAIR designated representative prior to the time and date when the Administrator receives the superseding certificate of representation shall be binding on the new alternate CAIR designated representative and the owners and operators of the CAIR source and the CAIR units at the source.

(c) Changes in owners and operators.

(1) In the event a new owner or operator of a CAIR source or a CAIR unit is not included in the list of owners and operators submitted in the certificate of representation under § 96.113, such new owner or operator shall be deemed to be subject to and bound by the certificate of representation, the representations, actions, inactions, and submissions of the CAIR designated representative and any alternate CAIR designated representative of the source or unit, and the decisions, orders, actions, and inactions of the permitting authority or the Administrator, as if the new owner or operator were included in such list.

(2) Within 30 days following any change in the owners and operators of a CAIR source or a CAIR unit, including the addition of a new owner or operator, the CAIR designated representative or alternate CAIR designated representative shall submit a revision to the certificate of representation under § 96.113 amending the list of owners and operators to include the change.

Certificate of representation.

(a) A complete certificate of representation for a CAIR designated representative or an alternate CAIR designated representative shall include the following elements in a format prescribed by the Administrator:

(1) Identification of the CAIR source and each CAIR unit at the source for which the certificate of representation is submitted.

(2) For each CAIR unit at the source, the dates on which the unit commenced operation and commenced commercial operation.

(3) The name, address, e-mail address (if any), telephone number, and facsimile transmission number (if any) of the CAIR designated representative and any alternate CAIR designated representative.

(4) A list of the owners and operators of the CAIR source and of each CAIR unit at the source.

(5) The following certification statements by the CAIR designated representative and any alternate CAIR designated representative—

(i) “I certify that I was selected as the CAIR designated representative or alternate CAIR designated representative, as applicable, by an agreement binding on the owners and operators of the source and each unit at the source.”

(ii) “I certify that I have all the necessary authority to carry out my duties and responsibilities under the CAIR SO2 and NOX Trading Programs on behalf of the owners and operators of the source and of each unit at the source and that each such owner and operator shall be fully bound by my representations, actions, inactions, or submissions.”

(iii) “I certify that the owners and operators of the source and of each unit at the source shall be bound by any order issued to me by the Administrator, the permitting authority, or a court regarding the source or unit.”Start Printed Page 32749

(iv) “Where there are multiple holders of a legal or equitable title to, or a leasehold interest in, a unit, or where a customer purchases power from a unit under life-of-the-unit, firm power contractual arrangements, I certify that: I have given a written notice of my selection as the “designated representative” or ‘alternated designated representative’, as applicable, and of the agreement by which I was selected to each owner and operator of the source and of each unit at the source; and allowances and proceeds of transactions involving allowances will be deemed to be held or distributed in proportion to each holder's legal, equitable, leasehold, or contractual reservation or entitlement or, if such multiple holders have expressly provided for a different distribution of allowances by contract, that allowances and the proceeds of transactions involving allowances will be deemed to be held or distributed in accordance with the contract.”

(6) The signature of the CAIR designated representative and any alternate CAIR designated representative and the dates signed.

(b) Unless otherwise required by the permitting authority or the Administrator, documents of agreement referred to in the certificate of representation shall not be submitted to the permitting authority or the Administrator. Neither the permitting authority nor the Administrator shall be under any obligation to review or evaluate the sufficiency of such documents, if submitted.

Objections concerning CAIR designated representative.

(a) Once a complete certificate of representation under § 96.113 has been submitted and received, the permitting authority and the Administrator will rely on the certificate of representation unless and until a superseding complete certificate of representation under § 96.113 is received by the Administrator.

(b) Except as provided in § 96.112(a) or (b), no objection or other communication submitted to the permitting authority or the Administrator concerning the authorization, or any representation, action, inaction, or submission of the CAIR designated representative shall affect any representation, action, inaction, or submission of the CAIR designated representative or the finality of any decision or order by the permitting authority or the Administrator under the CAIR NOX Trading Program.

(c) Neither the permitting authority nor the Administrator will adjudicate any private legal dispute concerning the authorization or any representation, action, inaction, or submission of any CAIR designated representative, including private legal disputes concerning the proceeds of CAIR NOX allowance transfers.

Subpart CC—Permits

General CAIR Trading Program permit requirements.

(a) For each CAIR source required to have a title V operating permit, such permit shall include a CAIR permit administered by the permitting authority for the title V operating permit. The CAIR portion of the title V permit shall be administered in accordance with the permitting authority's title V operating permits regulations promulgated under part 70 or 71 of this chapter, except as provided otherwise by this subpart.

(b) Each CAIR permit shall contain all applicable CAIR SO2 and NOX Trading Program requirements and shall be a complete and separable portion of the title V operating permit under paragraph (a) of this section.

Submission of CAIR permit applications.

(a) Duty to apply. The CAIR designated representative of any CAIR source required to have a title V operating permit shall submit to the permitting authority a complete CAIR permit application under § 96.122 by the applicable deadline in paragraph (b) of this section.

(b) Application deadline. For any source with any CAIR unit, the CAIR designated representative shall submit a complete CAIR permit application under § 96.122 covering such CAIR unit to the permitting authority at least 18 months (or such lesser time provided by the permitting authority) before the later of January 1, 2010 or the date on which the CAIR unit commences operation.

(c) Duty to Reapply. For a CAIR source required to have a title V operating permit, the CAIR designated representative shall submit a complete CAIR permit application under § 96.122 for the CAIR source covering the CAIR units at the source in accordance with the permitting authority's title V operating permits regulations addressing operating permit renewal.

Information requirements for CAIR permit applications.

A complete CAIR permit application shall include the following elements concerning the CAIR source for which the application is submitted, in a format prescribed by the permitting authority:

(a) Identification of the CAIR source, including plant name and the ORIS (Office of Regulatory Information Systems) or facility code assigned to the source by the Energy Information Administration, if applicable;

(b) Identification of each CAIR unit at the CAIR source; and

(c) The standard requirements under §§ 96.106 and 96.206.

CAIR permit contents and term.

(a) Each CAIR permit will contain, in a format prescribed by the permitting authority, all elements required for a complete CAIR permit application under § 96.122.

(b) Each CAIR permit is deemed to incorporate automatically the definitions of terms under § 96.102 and, upon recordation by the Administrator under subparts FF and GG of this part, every allocation, transfer, or deduction of a CAIR NOX allowance to or from the compliance account of the CAIR source covered by the permit.

(c) The term of the CAIR permit will be set by the permitting authority, as necessary to facilitate coordination of the renewal of the CAIR permit with issuance, revision, or renewal of the CAIR source's title V permit.

CAIR permit revisions.

Except as provided in § 96.123(b), the permitting authority will revise the CAIR permit, as necessary, in accordance with the permitting authority's title V operating permits regulations addressing permit revisions.

Subpart DD—[Reserved]

Subpart EE—CAIR NOX Allowance Allocations

State trading budgets.

The State trading program budgets for annual allocations of CAIR NOX allowances for 2010 through 2014 and for 2015 and thereafter are respectively as follows:

StateState NOX budget 2010 (tons)State NOX budget 2015 (tons)
Alabama67,42256,185
Start Printed Page 32750
Arkansas24,91920,765
Delaware5,0894,241
District of Columbia215179
Florida115,50396,253
Georgia63,57552,979
Illinois73,62261,352
Indiana102,29585,246
Iowa30,45825,381
Kansas32,43627,030
Kentucky77,93864,948
Louisiana47,33939,449
Maryland26,60722,173
Massachusetts19,63016,358
Michigan60,21250,177
Minnesota29,30324,420
Mississippi21,93218,277
Missouri56,57147,143
New Jersey9,8958,246
New York52,50343,753
North Carolina55,76346,469
Ohio101,70484,753
Pennsylvania84,55270,460
South Carolina30,89525,746
Tennessee47,73939,783
Texas224,314186,928
Virginia31,08725,906
West Virginia68,23556,863
Wisconsin39,04432,537
Total Regional Budget1,600,7991,333,999
Timing requirements for CAIR NOX allowance allocations.

(a)(1) By October 31, 2006, the permitting authority will submit to the Administrator the CAIR NOX allowance allocations, in a format prescribed by the Administrator and in accordance with § 96.142(a) and (b), for the control periods in 2010, 2011, 2012, 2013, and 2014.

(2) If the permitting authority fails to submit to the Administrator the CAIR NOX allowance allocations in accordance with paragraph (a)(1) of this section, the Administrator will allocate CAIR NOX allowances for the applicable control periods, in accordance with § 96.142(a) and (b).

(b)(1) By October 31, 2009 and October 31 of each year thereafter, the permitting authority will submit to the Administrator the CAIR NOX allowance allocations, in a format prescribed by the Administrator and in accordance with § 96.142(a) and (b), for the control period in the year that is 6 years after the year of the applicable deadline for submission under this paragraph.

(2) If the permitting authority fails to submit to the Administrator the CAIR NOX allowance allocations in accordance with paragraph (b)(1), the Administrator will allocate CAIR NOX allowances for the applicable control period, in accordance with § 96.142(a) and (b).

CAIR NOX allowance allocations.

(a)(1) The baseline heat input (in mmBtu) used with respect to CAIR NOX allowance allocations under paragraph (b) of this section for each CAIR unit will be:

(i) For units commencing operation before January 1, 1998 the average of the three highest amounts of the unit's annual heat input for 1998 through 2002.

(ii) For units commencing operation on or after January 1, 1998 and operating each year during a period of 5 or more consecutive years, the average of the three highest amounts of the unit's total converted annual heat input over the first such 5 years.

(2)(i) A unit's annual heat input for a year under paragraphs (a)(1)(i), (a)(2)(ii)(A), and (c)(3)(ii) of this section will be determined in accordance with part 75 of this chapter, if the CAIR unit was otherwise subject to the requirements of part 75 of this chapter for the year, or will be based on the best available data reported to the permitting authority for the unit, if the unit was not otherwise subject to the requirements of part 75 of this chapter for the year.

(ii) A unit's converted annual heat input for a year specified under paragraph (a)(1)(ii) of this section equals—

(A) The annual gross electrical output of the generator or generators served by the unit multiplied by 8,000 Btu/kWh, provided that if the generator is served by two or more units, then the gross electrical output of the generator will be attributed to each unit in proportion to the unit's share of total heat input of such units for the year; plus

(B) For a cogeneration unit, one-half of the unit's annual gross thermal energy multiplied by 8,000 Btu/kWh.

(b)(1) For each control period under § 96.141, the permitting authority will allocate to all CAIR units in the State that have a baseline heat input (as determined under paragraph (a) of this section) a total amount of CAIR NOX allowances equal to 98 percent of the tons of CAIR NOX emissions in the State trading program budget under § 96.140 (except as provided in § 96.142(d)).

(2) The permitting authority will allocate CAIR NOX allowances to each CAIR unit under paragraph (b)(1) of this section in an amount determined by multiplying the total amount of allowances allocated under paragraph (b)(1) of this section by the ratio of the baseline heat input of such unit to the total amount of baseline heat input of all CAIR units in the State and rounding to Start Printed Page 32751the nearest whole allowance as appropriate.

(c) For each control period under § 96.141, the permitting authority will allocate CAIR NOX allowances to CAIR units in the State that commenced operation on or after January 1, 1998 and do not yet have a baseline heat input (as determined under paragraph (a) of this section), in accordance with the following procedures:

(1) The permitting authority will establish a separate new unit set-aside for each control period. Each new unit set-aside will be allocated CAIR NOX allowances equal to 2 percent of the amount of tons of CAIR NOX emissions in the State trading program budget under § 96.140.

(2) The CAIR designated representative of such a CAIR unit may submit to the permitting authority a request, in a format specified by the permitting authority, to be allocated CAIR NOX allowances, starting with the first control period after the control period in which the CAIR unit commences commercial operation and until the first control period for which the unit is allocated CAIR NOX allowances under paragraph (b) of this section. The CAIR NOX allowance allocation request must be submitted before January 1 of the first control period for which the CAIR NOX allowances are requested and after the date on which the CAIR unit commences commercial operation.

(3) In a CAIR NOX allowance allocation request under paragraph (c)(2) of this section, the CAIR designated representative may request for a control period CAIR NOX allowances in an amount not exceeding—

(i) 1.00 lb/MWh for boilers, coal-fired combustion turbines, and integrated gasification combined cycle plants, 0.56 lb/MWh for gas-fired combustion turbines, or 1.01 lb/MWh for all other combustion turbines;

(ii) multiplied by the CAIR unit's heat input for the control period immediately preceding the control period for which the allowances are requested; and

(iii) rounded to the nearest whole allowance as appropriate.

(4) The permitting authority will review each CAIR NOX allowance allocation request under paragraph (c)(2) of this section and will allocate CAIR NOX allowances for each control period pursuant to such request as follows:

(i) Upon receipt of an allowance allocation request, the permitting authority will determine whether, and will make any necessary adjustments to the request to ensure that the request is consistent with the requirements of paragraphs (c)(2) and (3) of this section.

(ii) On or after January 1 of the control period, the permitting authority will determine the sum of the CAIR NOX allowances requested (as adjusted under paragraph (c)(4)(i) of this section) in all CAIR NOX allowance allocation requests under paragraph (c)(2) of this section for the control period.

(iii) If the amount of CAIR NOX allowances in the new unit set-aside for the control period is greater than or equal to the sum under paragraph (c)(4)(ii) of this section, the permitting authority will allocate the amount of CAIR NOX allowances requested (as adjusted under paragraph (c)(4)(i) of this section) to each CAIR unit covered by an allocation request under paragraph (c)(2) of this section.

(iv) If the amount of CAIR NOX allowances in the new unit set-aside for the control period is less than the sum under paragraph (c)(4)(ii) of this section, the permitting authority will allocate to each CAIR unit covered by an allocation request under paragraph (c)(2) of this section the amount of the CAIR NOX allowances requested (as adjusted under paragraph (c)(4)(i) of this section), multiplied by the number of CAIR NOX allowances in the new unit set-aside for the control period, divided by the sum determined under paragraph (c)(4)(ii) of this section, and rounded to the nearest whole allowance as appropriate.

(v) The permitting authority will notify each CAIR designated representative that submitted an allowance allocation request, and the Administrator (in a format prescribed by the Administrator), of the amount of CAIR NOX allowances (if any) allocated for the control period to the CAIR unit covered by the allowance allocation request.

(d) If, after completion of the procedures under paragraph (c)(4) of this section, any unallocated CAIR NOX allowances remain in the new unit set-aside for a control period, the permitting authority will reallocate to each CAIR unit that was allocated CAIR NOX allowances under paragraph (b) an amount of CAIR NOX allowances equal to the total amount of such remaining unallocated CAIR NOX allowances, multiplied by the unit's allocation under paragraph (b) of this section, divided by 98 percent of the amount of tons of CAIR NOX emissions in the State trading program budget, and rounded to the nearest whole allowance as appropriate. The permitting authority will notify the Administrator (in a format prescribed by the Administrator) of the amounts of CAIR NOX allowances (if any) allocated for the control period to such CAIR units under this paragraph.

Subpart FF—CAIR NOX Allowance Tracking System

CAIR NOX Allowance Tracking System Accounts.

(a) Nature and function of compliance accounts. Consistent with § 96.151(a), the Administrator will establish one compliance account for each CAIR source with one or more CAIR units. Allocations of CAIR NOX allowances to CAIR units pursuant to subpart EE of this part, and deductions or transfers of CAIR NOX allowances pursuant § 96.154, § 96.156, or subpart GG of this part will be recorded in compliance accounts in accordance with this subpart.

(b) Nature and function of general accounts. Consistent with § 96.151(b), the Administrator will establish, upon request, a general account for any person. Transfers of CAIR NOX allowances pursuant to subpart GG of this part will be recorded in general accounts in accordance with this subpart.

Establishment of accounts.

(a) Compliance accounts. Upon receipt of a complete certificate of representation under § 96.113, the Administrator will establish a compliance account for the CAIR source for which the certificate of representation was submitted.

(b) General accounts.

(1) Application for general account.

(i) Any person may apply to open a general account for the purpose of holding and transferring CAIR NOX allowances. An application for a general account may designate one and only one CAIR NOX authorized account representative and one and only one alternate CAIR NOX authorized account representative who may act on behalf of the CAIR NOX authorized account representative. The agreement by which the alternate CAIR NOX authorized account representative is selected shall include a procedure for authorizing the alternate CAIR NOX authorized account representative to act in lieu of the CAIR NOX authorized account representative.

(ii) A complete application for a general account shall be submitted to the Administrator and shall include the following elements in a format prescribed by the Administrator:

(A) Name, mailing address, e-mail address (if any), telephone number, and facsimile transmission number (if any) of the CAIR NOX authorized account representative and any alternate CAIR NOX authorized account representative; Start Printed Page 32752

(B) Organization name and type of organization;

(C) A list of all persons subject to a binding agreement for the CAIR NOX authorized account representative and any alternate CAIR NOX authorized account representative to represent their ownership interest with respect to the allowances held in the general account;

(D) The following certification statement by the CAIR NOX authorized account representative and any alternate CAIR NOX authorized account representative: “I certify that I was selected as the CAIR NOX authorized account representative or the CAIR NOX alternate authorized account representative, as applicable, by an agreement that is binding on all persons who have an ownership interest with respect to allowances held in the general account. I certify that I have all the necessary authority to carry out my duties and responsibilities under the CAIR NOX Trading Program on behalf of such persons and that each such person shall be fully bound by my representations, actions, inactions, or submissions and by any order or decision issued to me by the Administrator or a court regarding the general account.”

(E) The signature of the CAIR NOX authorized account representative and any alternate CAIR NOX authorized account representative and the dates signed.

(iii) Unless otherwise required by the permitting authority or the Administrator, documents of agreement referred to in the application for a general account shall not be submitted to the permitting authority or the Administrator. Neither the permitting authority nor the Administrator shall be under any obligation to review or evaluate the sufficiency of such documents, if submitted.

(2) Authorization of CAIR NOXauthorized account representative. Upon receipt by the Administrator of a complete application for a general account under paragraph (b)(1) of this section:

(i) The Administrator will establish a general account for the person or persons for whom the application is submitted.

(ii) The CAIR NOX authorized account representative and any alternate CAIR NOX authorized account representative for the general account shall represent and, by his or her representations, actions, inactions, or submissions, legally bind each person who has an ownership interest with respect to CAIR NOX allowances held in the general account in all matters pertaining to the CAIR NOX Trading Program, notwithstanding any agreement between the CAIR NOX authorized account representative or any alternate CAIR NOX authorized account representative and such person. Any such person shall be bound by any order or decision issued to the CAIR NOX authorized account representative or any alternate CAIR NOX authorized account representative by the Administrator or a court regarding the general account.

(iii) Any representation, action, inaction, or submission by any alternate CAIR NOX authorized account representative shall be deemed to be a representation, action, inaction, or submission by the CAIR NOX authorized account representative.

(iv) Each submission concerning the general account shall be submitted, signed, and certified by the CAIR NOX authorized account representative or any alternate CAIR NOX authorized account representative for the persons having an ownership interest with respect to CAIR NOX allowances held in the general account. Each such submission shall include the following certification statement by the CAIR NOX authorized account representative or any alternate CAIR NOX authorizing account representative: “I am authorized to make this submission on behalf of the persons having an ownership interest with respect to the CAIR NOX allowances held in the general account. I certify under penalty of law that I have personally examined, and am familiar with, the statements and information submitted in this document and all its attachments. Based on my inquiry of those individuals with primary responsibility for obtaining the information, I certify that the statements and information are to the best of my knowledge and belief true, accurate, and complete. I am aware that there are significant penalties for submitting false statements and information or omitting required statements and information, including the possibility of fine or imprisonment.”

(v) The Administrator will accept or act on a submission concerning the general account only if the submission has been made, signed, and certified in accordance with paragraph (b)(2)(iv) of this section.

(3) Changing CAIR NOXauthorized account representative and alternate CAIR NOXauthorized account representative; changes in persons with ownership interest.

(i) The CAIR NOX authorized account representative for a general account may be changed at any time upon receipt by the Administrator of a superseding complete application for a general account under paragraph (b)(1) of this section. Notwithstanding any such change, all representations, actions, inactions, and submissions by the previous CAIR NOX authorized account representative prior to the time and date when the Administrator receives the superseding application for a general account shall be binding on the new CAIR NOX authorized account representative and the persons with an ownership interest with respect to the CAIR NOX allowances in the general account.

(ii) The alternate CAIR NOX authorized account representative for a general account may be changed at any time upon receipt by the Administrator of a superseding complete application for a general account under paragraph (b)(1) of this section. Notwithstanding any such change, all representations, actions, inactions, and submissions by the previous alternate CAIR NOX authorized account representative prior to the time and date when the Administrator receives the superseding application for a general account shall be binding on the new alternate CAIR NOX authorized account representative and the persons with an ownership interest with respect to the CAIR NOX allowances in the general account.

(iii)(A) In the event a new person having an ownership interest with respect to CAIR NOX allowances in the general account is not included in the list of such persons in the application for a general account, such new person shall be deemed to be subject to and bound by the application for a general account, the representation, actions, inactions, and submissions of the CAIR NOX authorized account representative and any alternate CAIR NOX authorized account representative of the account, and the decisions, orders, actions, and inactions of the Administrator, as if the new person were included in such list.

(B) Within 30 days following any change in the persons having an ownership interest with respect to CAIR NOX allowances in the general account, including the addition of persons, the CAIR NOX authorized account representative or any alternate CAIR NOX authorized account representative shall submit a revision to the application for a general account amending the list of persons having an ownership interest with respect to the CAIR NOX allowances in the general account to include the change.

(4) Objections concerning CAIR NOX authorized account representative.

(i) Once a complete application for a general account under paragraph (b)(1) of this section has been submitted and received, the Administrator will rely on the application unless and until a Start Printed Page 32753superseding complete application for a general account under paragraph (b)(1) of this section is received by the Administrator.

(ii) Except as provided in paragraph (b)(3) (i) or (ii) of this section, no objection or other communication submitted to the Administrator concerning the authorization, or any representation, action, inaction, or submission of the CAIR NOX authorized account representative or any alternative CAIR NOX authorized account representative for a general account shall affect any representation, action, inaction, or submission of the CAIR NOX authorized account representative or any alternative CAIR NOX authorized account representative or the finality of any decision or order by the Administrator under the CAIR NOX Trading Program.

(iii) The Administrator will not adjudicate any private legal dispute concerning the authorization or any representation, action, inaction, or submission of the CAIR NOX authorized account representative or any alternative CAIR NOX authorized account representative for a general account, including private legal disputes concerning the proceeds of CAIR NOX allowance transfers.

(c) Account identification. The Administrator will assign a unique identifying number to each account established under paragraph (a) or (b) of this section.

Responsibilities of CAIR NOX authorized account representative.

(a) Following the establishment of a CAIR NOX Allowance Tracking System account, all submissions to the Administrator pertaining to the account, including, but not limited to, submissions concerning the deduction or transfer of CAIR NOX allowances in the account, shall be made only by the CAIR NOX authorized account representative for the account.

(b) Authorized account representative identification. The Administrator will assign a unique identifying number to each CAIR NOX authorized account representative.

Recordation of CAIR NOX allowance allocations.

(a) By January 1, 2007, the Administrator will record the CAIR NOX allowances for 2010, 2011, 2012, 2013, and 2014 for the CAIR units at a source allocated in accordance with § 96.142 (a) and (b) in the source's compliance account.

(b) Each year starting with 2011, after the Administrator has made all deductions from a CAIR source's compliance account under § 96.154, the Administrator will record CAIR NOX allowances, in the source's compliance account, as allocated to the CAIR units at the source in accordance with § 96.142 (a) and (b), for the fourth year after the year of the control period for which such deductions were or could have been made.

(c) Each year starting with 2010, after the Administrator is notified, in accordance with § 96.142(c) (v) and (d), by the permitting authority of the amounts of CAIR NOX allowances allocated to the CAIR units at the source, the Administrator will record the allocated allowances in the source's compliance account.

(d) Serial numbers for allocated CAIR NOXallowances. When allocating CAIR NOX allowances to a CAIR unit and recording them in an account, the Administrator will assign each CAIR NOX allowance a unique identification number that will include digits identifying the year for which the CAIR NOX allowance is allocated.

Compliance with CAIR NOX emissions limitation.

(a) CAIR NOXallowance transfer deadline. The CAIR NOX allowances are available to be deducted for compliance with a source's CAIR NOX emissions limitation for a control period in a given year only if the CAIR NOX allowances:

(1) Were allocated for the year or a prior year;

(2) Are held in the compliance account as of the CAIR NOX allowance transfer deadline for the control period or are transferred into the compliance account by a CAIR NOX allowance transfer correctly submitted for recordation under § 96.160 by the CAIR NOX allowance transfer deadline for the control period; and

(3) Are not necessary for deductions for excess emissions for a prior control period under paragraph (d) of this section.

(b) Deductions for compliance. Following the recordation, in accordance with § 96.161, of CAIR NOX allowance transfers submitted for recordation in a source's compliance account by the CAIR NOX allowance transfer deadline for a control period, the Administrator will deduct from the compliance account CAIR NOX allowances available under paragraph (a) of this section in order to determine whether the source meets the CAIR NOX emissions limitation for the control period, as follows:

(1) Until the amount of CAIR NOX allowances deducted equals the number of tons of total nitrogen oxides emissions, determined in accordance with subpart HH of this part, from all CAIR units at the source for the control period; or

(2) Until no more CAIR NOX allowances available under paragraph (a) of this section remain in the compliance account.

(c)(1) Identification of CAIR NOXallowances by serial number. The CAIR NOX authorized account representative for a source's compliance account may request that specific CAIR NOX allowances, identified by serial number, in the compliance account be deducted for emissions or excess emissions for a control period in accordance with paragraph (b) or (d) of this section. Such request shall be submitted to the Administrator by the allowance transfer deadline for the control period and include, in a format prescribed by the Administrator, the identification of the CAIR source and the appropriate serial numbers.

(2) First-in, first-out. The Administrator will deduct CAIR NOX allowances under paragraph (b) or (d) of this section from the source's compliance account, in the absence of an identification or in the case of a partial identification of CAIR NOX allowances by serial number under paragraph (c)(1) of this section, on a first-in, first-out (FIFO) accounting basis in the following order:

(i) Those CAIR NOX allowances that were allocated to the units at the source under subpart EE of this part, in the order of recordation; and then

(ii) Those CAIR NOX allowances that were allocated to any unit and transferred and recorded in the compliance account pursuant to subpart GG of this part, in the order of recordation.

(d) Deductions for excess emissions.

(1) After making the deductions for compliance under paragraph (b) of this section for a control period in which the CAIR source has excess emissions, the Administrator will deduct from the source's compliance account an amount of CAIR NOX allowances, allocated for the year after such control period, equal to three times the number of tons of the source's excess emissions.

(2) Any allowance deduction required under paragraph (d)(1) of this section shall not affect the liability of the owners and operators of the CAIR source or the CAIR units at the source for any fine, penalty, or assessment, or their obligation to comply with any other remedy, for the same violation, as ordered under the Clean Air Act or applicable State law. The following guidelines will be followed in assessing fines, penalties or other obligations:Start Printed Page 32754

(i) For purposes of determining the number of days of violation, if a CAIR source has excess emissions for a control period, each day in the control period constitutes a day in violation unless the owners and operators of the source demonstrate that a lesser number of days should be considered.

(ii) Each ton of excess emissions is a separate violation.

(e) Recordation of deductions. The Administrator will record in the appropriate compliance account all deductions from such an account under paragraph (b) or (d) of this section.

(f) Administrator's action on submissions.

(1) The Administrator may review and conduct independent audits concerning any submission under the CAIR NOX Trading Program and make appropriate adjustments of the information in the submissions.

(2) The Administrator may deduct CAIR NOX allowances from or transfer CAIR NOX allowances to a source's compliance account based on the information in the submissions, as adjusted under paragraph (f)(1) of this section.

Banking.

(a) CAIR NOX allowances may be banked for future use or transfer in a compliance account or a general account in accordance with paragraph (b) of this section.

(b) Any CAIR NOX allowance that is held in a compliance account or a general account will remain in such account unless and until the CAIR NOX allowance is deducted or transferred under § 96.154, § 96.156, or subpart GG of this part.

Account error.

The Administrator may, at his or her sole discretion and on his or her own motion, correct any error in any CAIR NOX Allowance Tracking System account. Within 10 business days of making such correction, the Administrator will notify the CAIR NOX authorized account representative for the account.

Closing of general accounts.

(a) The CAIR NOX authorized account representative of a general account may submit to the Administrator a request to close the account, which shall include a correctly submitted allowance transfer under § 96.160 for any CAIR NOX allowances in the account to one or more other CAIR NOX Allowance Tracking System accounts.

(b) If a general account has no allowance transfers in or out of the account and does not contain any CAIR NOX allowances, the Administrator may notify the CAIR NOX authorized account representative for the account that the account will be closed following 20 business days after the notice is sent. The account will be closed after the 20-day period unless, before the end of the 20-day period, the Administrator receives a correctly submitted transfer of CAIR NOX allowances into the account under § 96.160 or a statement submitted by the CAIR NOX authorized account representative demonstrating to the satisfaction of the Administrator good cause as to why the account should not be closed.

Subpart GG—CAIR NOX Allowance Transfers

Submission of CAIR NOX allowance transfers.

An CAIR NOX authorized account representative seeking recordation of a CAIR NOX allowance transfer shall submit the transfer to the Administrator. To be considered correctly submitted, the CAIR NOX allowance transfer shall include the following elements, in a format specified by the Administrator:

(a) The numbers identifying both the transferor and transferee accounts;

(b) The serial number of each CAIR NOX allowance (which must be in transferor account) to be transferred; and

(c) The name and signature of the CAIR NOX authorized account representative of the transferor account and the date signed.

EPA recordation.

(a) Within 5 business days of receiving a CAIR NOX allowance transfer, except as provided in paragraph (b) of this section, the Administrator will record a CAIR NOX allowance transfer by moving each CAIR NOX allowance from the transferor account to the transferee account as specified by the request, provided that:

(1) The transfer is correctly submitted under § 96.160; and

(2) The transferor account includes each CAIR NOX allowance identified by serial number in the transfer.

(b) a CAIR NOX allowance transfer that is submitted for recordation after the CAIR NOX allowance transfer deadline and that includes any CAIR NOX allowances allocated for a control period in any year before the year of the CAIR NOX allowance transfer deadline will not be recorded until after the Administrator completes the deductions under § 96.154 for the control period in the year immediately before the year of the CAIR NOX allowance transfer deadline.

(c) Where a CAIR NOX allowance transfer submitted for recordation fails to meet the requirements of paragraph (a) of this section, the Administrator will not record such transfer.

Notification.

(a) Notification of recordation. Within 5 business days of recordation of a CAIR NOX allowance transfer under § 96.161, the Administrator will notify the CAIR NOX authorized account representatives of both the transferor and transferee accounts.

(b) Notification of non-recordation. Within 10 business days of receipt of a CAIR NOX allowance transfer that fails to meet the requirements of § 96.161(a), the Administrator will notify the CAIR NOX authorized account representatives of both accounts subject to the transfer of:

(1) A decision not to record the transfer, and

(2) The reasons for such non-recordation.

(c) Nothing in this section shall preclude the submission of a CAIR NOX allowance transfer for recordation following notification of non-recordation.

Subpart HH—Monitoring and Reporting

General Requirements.

The owners and operators, and to the extent applicable, the CAIR designated representative, of a CAIR unit, shall comply with the monitoring, recordkeeping, and reporting requirements as provided in this subpart and in subpart H of part 75 of this chapter. For purposes of complying with such requirements, the definitions in § 96.102 and in § 72.2 of this chapter shall apply, and the terms “affected unit,” “designated representative,” and “continuous emission monitoring system” (or “CEMS”) in part 75 of this chapter shall be deemed to refer to the terms “CAIR unit,” “CAIR designated representative,” and “continuous emission monitoring system” (or “CEMS”) respectively, as defined in § 96.102. The owner or operator of a unit that is not a CAIR unit but that is monitored under § 75.72(b)(2)(ii) of this chapter shall comply with the same monitoring, recordkeeping, and reporting requirements as a CAIR unit.

(a) Requirements for installation, certification, and data accounting. The owner or operator of each CAIR unit shall:

(1) Install all monitoring systems required under this subpart for monitoring NOX mass emissions and individual unit heat input. This Start Printed Page 32755includes all systems required to monitor NOX emission rate, NOX concentration, stack gas moisture content, stack gas flow rate, CO2 or O2 concentration, and fuel flow rate, in accordance with §§ 75.71 and 75.72 of this chapter;

(2) Successfully complete all certification tests required under § 96.171 and meet all other requirements of this subpart and part 75 of this chapter applicable to the monitoring systems under paragraph (a)(1) of this section; and

(3) Record, report, and quality-assure the data from the monitoring systems under paragraph (a)(1) of this section.

(b) Compliance deadlines. The owner or operator shall meet the certification and other requirements of paragraphs (a)(1) and (a)(2) of this section on or before the following dates. The owner or operator shall record, report, and quality-assure the data from the monitoring systems under paragraph (a)(1) of this section on and after the following dates.

(1) For the owner or operator of a CAIR unit that commences commercial operation before July 1, 2008, by January 1, 2009.

(2) For the owner or operator of a CAIR unit that commences commercial operation on or after July 1, 2008, by the later of the following dates:

(i) January 1, 2009; or

(ii) 90 unit operating days or 180 calendar days, whichever occurs first, after the date on which the unit commences commercial operation.

(3) For the owner or operator of a CAIR unit for which construction of a new stack or flue or installation of add-on NOX emission controls is completed after the applicable deadline under paragraph (b)(1) or (b)(2) of this section, by the earlier of 90 unit operating days or 180 calendar days after the date on which emissions first exit to the atmosphere through the new stack or flue or add-on NOX emissions controls.

(c) Reporting data prior to initial certification. The owner or operator of a CAIR unit that does not meet the applicable compliance date set forth in paragraph (b) of this section shall determine, record, and report maximum potential (or, in some cases, minimum potential) values for NOX concentration, NOX emission rate, stack gas flow rate, stack gas moisture content, fuel flow rate, and any other parameters required to determine NOX mass emissions and heat input in accordance with § 75.31(b)(2) or § 75.31(c)(3) of this chapter, § 2.4 of appendix D to part 75 of this chapter, or § 2.5 of appendix E to part 75 of this chapter, as applicable.

(d) Prohibitions

(1) No owner or operator of a CAIR unit shall use any alternative monitoring system, alternative reference method, or any other alternative for the required continuous emission monitoring system without having obtained prior written approval in accordance with § 96.175.

(2) No owner or operator of a CAIR unit shall operate the unit so as to discharge, or allow to be discharged, NOX emissions to the atmosphere without accounting for all such emissions in accordance with the applicable provisions of this subpart and part 75 of this chapter.

(3) No owner or operator of a CAIR unit shall disrupt the continuous emission monitoring system, any portion thereof, or any other approved emission monitoring method, and thereby avoid monitoring and recording NOX mass emissions discharged into the atmosphere, except for periods of recertification or periods when calibration, quality assurance testing, or maintenance is performed in accordance with the applicable provisions of this subpart and part 75 of this chapter.

(4) No owner or operator of a CAIR unit shall retire or permanently discontinue use of the continuous emission monitoring system, any component thereof, or any other approved monitoring system under this subpart, except under any one of the following circumstances:

(i) During the period that the unit is covered by an exemption under § 96.105 that is in effect;

(ii) The owner or operator is monitoring emissions from the unit with another certified monitoring system approved, in accordance with the applicable provisions of this subpart and part 75 of this chapter, by the permitting authority for use at that unit that provides emission data for the same pollutant or parameter as the retired or discontinued monitoring system; or

(iii) The CAIR designated representative submits notification of the date of certification testing of a replacement monitoring system for the retired or discontinued monitoring system in accordance with § 96.171(d)(3)(i).

Initial certification and recertification procedures.

(a) The owner or operator of a CAIR unit shall be exempt from the initial certification requirements of this section if the following conditions are met:

(1) In 2008, the unit is subject to an Acid Rain emission limitation or is subject to the NOX Budget Trading Program or another applicable State or Federal NOX mass emission reduction program that has adopted the requirements of subpart H of part 75 of this chapter; and

(2) Under the Acid Rain Program or the NOX mass emission reduction program described in paragraph (a)(1) of this section, all of the monitoring systems required under this subpart for monitoring NOX mass emissions and heat input have been previously certified in accordance with subpart H of part 75 of this chapter; and

(3) The applicable quality-assurance requirements of § 75.21 or § 75.74(c) of this chapter, or appendix B, appendix D, or appendix E to part 75 of this chapter are fully met in 2008 for all of the certified monitoring systems described in paragraph (a)(2) of this section.

(b) The recertification provisions of this section shall apply to the monitoring systems exempted from initial certification requirements under paragraph (a) of this section.

(c) If the Administrator has previously approved a petition under § 75.17(a) or (b) of this chapter for apportioning the NOX emission rate measured in a common stack or a petition under § 75.66 of this chapter for an alternative to a requirement in § 75.17 or subpart H of part 75 of this chapter, the CAIR designated representative shall resubmit the petition to the Administrator under § 96.175(a) to determine whether the approval applies under the CAIR NOX Trading Program.

(d) The owner or operator of a CAIR unit that is not exempted under paragraph (a) of this section from the initial certification requirements of this section shall comply with the following initial certification and recertification procedures, for CEMS and for excepted monitoring systems under appendices D and E to part 75 of this chapter. The owner or operator of a unit that qualifies to use the low mass emissions excepted monitoring methodology under § 75.19 of this chapter or that qualifies to use an alternative monitoring system under subpart E of part 75 of this chapter shall comply with the procedures in paragraph (e) or (f) of this section respectively.

(1) Requirements for initial certification. The owner or operator shall ensure that each monitoring system required by subpart H of part 75 of this chapter (including the automated data acquisition and handling system) successfully completes all of the initial certification testing required under § 75.20 of this chapter by the applicable deadline in § 96.170(b). In addition, whenever the owner or operator installs a monitoring system to meet the requirements of this subpart in a location where no such monitoring Start Printed Page 32756system was previously installed, initial certification in accordance with § 75.20 of this chapter is required.

(2) Requirements for recertification. Whenever the owner or operator makes a replacement, modification, or change in any certified continuous monitoring system required by subpart H of part 75 of this chapter that may significantly affect the ability of the system to accurately measure or record NOX mass emissions or heat input rate or to meet the requirements of § 75.21 of this chapter or appendix B to part 75 of this chapter, the owner or operator shall recertify the monitoring system in accordance with § 75.20(b) of this chapter. Furthermore, whenever the owner or operator makes a replacement, modification, or change to the flue gas handling system or the unit's operation that may significantly change the stack flow or concentration profile, the owner or operator shall recertify each continuous emission monitoring system whose accuracy is potentially affected by the change, in accordance with § 75.20(b) of this chapter. Examples of changes to CEMS that require recertification include: replacement of the analyzer, complete replacement of an existing continuous emission monitoring system, or change in location or orientation of the sampling probe or site. Fuel flowmeter systems and excepted NOX monitoring systems under appendix E to part 75 of this chapter are subject to the recertification requirements in § 75.20(g)(6) of this chapter.

(3) Approval process for initial certification and recertification. Paragraphs (d)(3)(i) through (d)(3)(iv) of this section apply to both initial certification and recertification of continuous monitoring systems. For recertifications, replace the words “certification” and “initial certification” with the word “recertification”, replace the word “certified” with the word “recertified,” and follow the procedures in §§ 75.20(b)(5) and (g)(7) of this chapter in lieu of the procedures in paragraph (d)(3)(v) of this section.

(i) Notification of certification. The CAIR designated representative shall submit to the permitting authority, to the appropriate EPA Regional Office, and to the Administrator written notice of the dates of certification testing, in accordance with § 96.173.

(ii) Certification application. The CAIR designated representative shall submit to the permitting authority a certification application for each monitoring system required under subpart H of part 75 of this chapter. A complete certification application shall include the information specified in § 75.63 of this chapter.

Notwithstanding this requirement, a certification application is not required by subpart H if the monitoring system has been previously certified in accordance with the Acid Rain Program or in accordance with the NOX Budget Trading Program or another applicable State or Federal NOX mass emission reduction program that adopts the requirements of subpart H of part 75 of this chapter.

(iii) Provisional certification date. Except for units using the low mass emission excepted methodology under § 75.19 of this chapter, the provisional certification date for a monitoring system shall be determined in accordance with § 75.20(a)(3) of this chapter. A provisionally certified monitoring system may be used under the CAIR NOX Trading Program for a period not to exceed 120 days after receipt by the permitting authority of the complete certification application for the monitoring system under paragraph (d)(3)(ii) of this section. Data measured and recorded by the provisionally certified monitoring system, in accordance with the requirements of part 75 of this chapter, will be considered valid quality-assured data (retroactive to the date and time of provisional certification), provided that the permitting authority does not invalidate the provisional certification by issuing a notice of disapproval within 120 days of the date of receipt of the complete certification application by the permitting authority.

(iv) Certification application formal approval process. The permitting authority will issue a written notice of approval or disapproval of the certification application to the owner or operator within 120 days of receipt of the complete certification application under paragraph (d)(3)(ii) of this section. In the event the permitting authority does not issue such a notice within such 120-day period, each monitoring system that meets the applicable performance requirements of part 75 of this chapter and is included in the certification application will be deemed certified for use under the CAIR NOX Trading Program.

(A) Approval notice. If the certification application is complete and shows that each monitoring system meets the applicable performance requirements of part 75 of this chapter, then the permitting authority will issue a written notice of approval of the certification application within 120 days of receipt.

(B) Incomplete application notice. A certification application will be considered complete when all of the applicable information required to be submitted under paragraph (d)(3)(ii) of this section has been received by the permitting authority. If the certification application is not complete, then the permitting authority will issue a written notice of incompleteness that sets a reasonable date by which the CAIR designated representative must submit the additional information required to complete the certification application. If the CAIR designated representative does not comply with the notice of incompleteness by the specified date, then the permitting authority may issue a notice of disapproval under paragraph (d)(3)(iv)(C) of this section. The 120-day review period shall not begin prior to receipt of a complete certification application.

(C) Disapproval notice. If the certification application shows that any monitoring system does not meet the performance requirements of part 75 of this chapter, or if the certification application is incomplete and the requirement for disapproval under paragraph (d)(3)(iv)(B) of this section has been met, then the permitting authority will issue a written notice of disapproval of the certification application. Upon issuance of such notice of disapproval, the provisional certification is invalidated by the permitting authority and the data measured and recorded by each uncertified monitoring system shall not be considered valid quality-assured data beginning with the date and hour of provisional certification (as defined under § 75.20(a)(3) of this chapter). The owner or operator shall follow the procedures for loss of certification in paragraph (d)(3)(v) of this section for each monitoring system that is disapproved for initial certification.

(D) Audit decertification. The permitting authority may issue a notice of disapproval of the certification status of a monitor in accordance with § 96.172(b).

(v) Procedures for loss of certification. If the permitting authority issues a notice of disapproval of a certification application under paragraph (d)(3)(iv)(C) of this section or a notice of disapproval of certification status under paragraph (d)(3)(iv)(D) of this section, then:

(A) The owner or operator shall substitute the following values, for each disapproved monitoring system, for each hour of unit operation during the period of invalid data specified under § 75.20(a)(4)(iii), § 75.20(b)(5), § 75.21(e), or § 75.20(g)(7) of this chapter and continuing until the applicable date Start Printed Page 32757and hour specified under § 75.20(a)(5)(i) or (g)(7) of this chapter:

(1) For a disapproved NOX emission rate (i.e., NOX-diluent) system, the maximum potential NOX emission rate, as defined in § 72.2 of this chapter.

(2) For disapproved NOX pollutant concentration monitors and flow monitors, respectively, the maximum potential concentration of NOX and the maximum potential flow rate, as defined in § 2 of appendix A to part 75 of this chapter.

(3) For disapproved moisture and diluent gas monitoring systems, respectively, the minimum potential moisture percentage and either the maximum potential CO2 concentration or the minimum potential O2 concentration (as applicable), as defined in § 2 of appendix A to part 75 of this chapter.

(4) For disapproved fuel flowmeter systems, the maximum potential fuel flow rate, as defined in § 2.4.2.1 of appendix D to part 75 of this chapter.

(5) For a disapproved excepted NOX monitoring system under appendix E to part 75 of this chapter, the fuel-specific maximum potential NOX emission rate, as defined in § 72.2 of this chapter.

(B) The CAIR designated representative shall submit a notification of certification retest dates and a new certification application in accordance with paragraphs (d)(3)(i) and (ii) of this section.

(C) The owner or operator shall repeat all certification tests or other requirements that were failed by the monitoring system, as indicated in the permitting authority's notice of disapproval, no later than 30 unit operating days after the date of issuance of the notice of disapproval.

(e) Initial certification and recertification procedures for units using the low mass emission excepted methodology under § 75.19 of this chapter. The owner or operator of a gas-fired or oil-fired (as defined in § 72.2 of this chapter) unit using low mass emissions (LME) excepted methodology under § 75.19 of this chapter shall meet the applicable certification and recertification requirements in §§ 75.19(a)(2) and 75.20(h) in part 75 of this chapter. If the owner or operator of a low mass emissions unit elects to certify a fuel flowmeter system for heat input determination, the owner or operator shall also meet the certification and recertification requirements in § 75.20(g) of this chapter.

(f) Certification/recertification procedures for alternative monitoring systems. The CAIR designated representative of each unit for which the owner or operator intends to use an alternative monitoring system approved by the Administrator and, if applicable, the permitting authority under subpart E of part 75 of this chapter shall comply with the notification and application procedures of paragraph (d)(1) of this section before using the system under the CAIR NOX Trading Program. The CAIR designated representative shall also comply with the applicable notification and application procedures of paragraph (d)(2) of this section. Section 75.20(f) of this chapter shall apply to such alternative monitoring system.

Out of control periods.

(a) Whenever any monitoring system fails to meet the quality assurance or data validation requirements of part 75 of this chapter, data shall be substituted using the applicable procedures in subpart D, subpart H, appendix D, or appendix E of part 75 of this chapter.

(b) Audit decertification. Whenever both an audit of a monitoring system and a review of the initial certification or recertification application reveal that any system should not have been certified or recertified because it did not meet a particular performance specification or other requirement under § 96.171 or the applicable provisions of part 75 of this chapter, both at the time of the initial certification or recertification application submission and at the time of the audit, the permitting authority will issue a notice of disapproval of the certification status of such system. For the purposes of this paragraph, an audit shall be either a field audit or an audit of any information submitted to the permitting authority or the Administrator. By issuing the notice of disapproval, the permitting authority revokes prospectively the certification status of the system. The data measured and recorded by the system shall not be considered valid quality-assured data from the date of issuance of the notification of the revoked certification status until the date and time that the owner or operator completes subsequently approved initial certification or recertification tests for the system. The owner or operator shall follow the applicable initial certification or recertification procedures in § 96.171 for each disapproved system.

Notifications.

The CAIR designated representative for a CAIR unit shall submit written notice to the permitting authority and the Administrator in accordance with § 75.61 of this chapter, except that if the unit is not subject to an Acid Rain emissions limitation, the notification is only required to be sent to the permitting authority.

Recordkeeping and reporting.

(a) General provisions.

(1) The CAIR designated representative shall comply with all recordkeeping and reporting requirements in this section, the applicable recordkeeping and reporting requirements under § 75.73 of this chapter, and the requirements of § 96.110(e)(1).

(b) Monitoring Plans. The owner or operator of a CAIR unit shall comply with requirements of §§ 75.73(c) and (e) of this chapter.

(c) Certification Applications. The CAIR designated representative shall submit an application to the permitting authority within 45 days after completing all initial certification or recertification tests required under § 96.171, including the information required under § 75.63 of this chapter.

(d) Quarterly reports. The CAIR designated representative shall submit quarterly reports, as follows:

(1) The CAIR designated representative shall report NOX mass emissions data and heat input data, in an electronic quarterly report in a format prescribed by the Administrator, for each calendar quarter beginning with:

(i) For a unit that commences commercial operation before July 1, 2008, the calendar quarter covering January 1, 2009 through March 31, 2009. Data shall be reported from the first hour on January 1, 2009; or

(ii) For a unit that commences commercial operation on or after July 1, 2008, the calendar quarter corresponding to the earlier of the date of provisional certification or the relevant deadline for initial certification under § 96.170(b), unless that quarter is the third or fourth quarter of 2008, in which case reporting shall commence in the quarter covering January 1, 2009 through March 31, 2009. Data shall be reported from the later of the date and hour corresponding to the date and hour of provisional certification or the first hour on January 1, 2009.

(2) The CAIR designated representative shall submit each quarterly report to the Administrator within 30 days following the end of the calendar quarter covered by the report. Quarterly reports shall be submitted in the manner specified in § 75.73(f) of this chapter.

(3) For CAIR units that are also subject to an Acid Rain emissions limitation, the NOX Budget Trading Program or another applicable State or Federal NOX mass emission reduction Start Printed Page 32758program that adopts the requirements of subpart H of part 75 of this chapter, or an applicable State or Federal Hg mass emission reduction program that adopts the requirements of subpart I of part 75 of this chapter, quarterly reports shall include the applicable data and information required by subparts F through I of part 75 of this chapter as applicable, in addition to the NOX mass emission data, heat input data, and other information required by this subpart.

(e) Compliance certification. The CAIR designated representative shall submit to the Administrator a compliance certification (in a format prescribed by the Administrator) in support of each quarterly report based on reasonable inquiry of those persons with primary responsibility for ensuring that all of the unit's emissions are correctly and fully monitored. The certification shall state that:

(1) The monitoring data submitted were recorded in accordance with the applicable requirements of this subpart and part 75 of this chapter, including the quality assurance procedures and specifications; and

(2) For a unit with add-on NOX emission controls and for all hours where NOX data are substituted in accordance with § 75.34(a)(1) of this chapter, the add-on emission controls were operating within the range of parameters listed in the quality assurance/quality control program under appendix B of part 75 of this chapter and the substitute data values do not systematically underestimate NOX emissions.

Petitions.

(a) The CAIR designated representative of a CAIR unit that is subject to an Acid Rain emissions limitation may submit a petition under § 75.66 of this chapter to the Administrator requesting approval to apply an alternative to any requirement of this subpart. Application of an alternative to any requirement of this subpart is in accordance with this subpart only to the extent that the petition is approved by the Administrator, in consultation with the permitting authority.

(b) The CAIR designated representative of a CAIR unit that is not subject to an Acid Rain emissions limitation may submit a petition under § 75.66 of this chapter to the permitting authority and the Administrator requesting approval to apply an alternative to any requirement of this subpart. Application of an alternative to any requirement of this subpart is in accordance with this subpart only to the extent that the petition is approved by both the permitting authority and the Administrator.

Additional requirements to provide heat input data.

The owner or operator of a CAIR unit that monitors and reports NOX mass emissions using a NOX concentration system and a flow system shall also monitor and report heat input rate at the unit level using the procedures set forth in part 75 of this chapter.

3. Part 96 is amended by adding subparts AAA through CCC, adding and reserving subparts DDD and EEE and adding subparts FFF through HHH to read as follows:

Subpart AAA—CAIR SO2 Trading Program General Provisions
Purpose.
Definitions.
Measurements, abbreviations, and acronyms.
Applicability.
Retired unit exemption.
Standard requirements.
Computation of time.
Appeal Procedures.
Subpart BBB—CAIR Designated Representative for CAIR Sources
Authorization and responsibilities of CAIR designated representative.
Alternate CAIR designated representative.
Changing CAIR designated representative and alternate CAIR designated representative; changes in owners and operators.
Certificate of representation.
Objections concerning CAIR designated representative.
Subpart CCC—Permits
General CAIR SO2 Trading Program permit requirements.
Submission of CAIR permit applications.
Information requirements for CAIR permit applications.
CAIR permit contents and term.
CAIR permit revisions.
Subpart DDD—[Reserved] Subpart EEE—[Reserved] Subpart FFF—CAIR SO2 Allowance Tracking System
CAIR SO2 Allowance Tracking System accounts.
Establishment of accounts.
Responsibilities of CAIR SO2 authorized account representative.
[Reserved]
Compliance with CAIR SO2 emissions limitation.
Banking.
Account error.
Closing of general accounts.
Subpart GGG—CAIR SO2 Allowance Transfers
Submission of CAIR SO2 allowance transfers.
EPA recordation.
Notification.
Subpart HHH—Monitoring and Reporting
General requirements.
Initial certification and recertification procedures.
Out of control periods.
Notifications.
Recordkeeping and reporting.
Petitions.
Additional requirements to provide heat input data.
Subpart AAA—(CAIR) SO2 Trading Program General Provisions
Purpose.

This subpart establishes the model rule comprising general provisions and the applicability, permitting, allowance, excess emissions, and monitoring for the state Clean Air Interstate Rule (CAIR) SO2 Trading Program, under § 110 of the Clean Air Act (CAA) and § 51.124 of this chapter, as a means of reducing national SO2 emissions.

Definitions.

The terms used in this subpart shall have the meanings set forth in this section as follows:

Account number means the identification number given by the Administrator to each CAIR SO2 Allowance Tracking System account.

Acid Rain emissions limitation means a limitation on emissions of sulfur dioxide or nitrogen oxides under the Acid Rain Program.

Acid Rain Program means a multi-state sulfur dioxide and nitrogen oxides air pollution control and emission reduction program established by the Administrator under title IV of the CAA and parts 72 through 78 of this chapter.

Administrator means the Administrator of the United States Environmental Protection Agency or the Administrator's duly authorized representative.

Allocate or allocation means, with regard to CAIR SO allowances, the determination by the Administrator of the amount of CAIR SO2 allowances to be initially credited to a CAIR unit.

Alternate CAIR designated representative means, for a CAIR source and each CAIR unit at the source, the natural person who is authorized by the owners and operators of the source and all CAIR units at the source in accordance with subpart BBB of this part, to act on behalf of the CAIR designated representative in matters pertaining to the CAIR SO2 Trading Program and the CAIR NOX Trading Start Printed Page 32759Program. This natural person shall be the same person as the alternate designated representative under the Acid Rain Program under § 72.22 of this chapter.

Automated data acquisition and handling system or DAHS means that component of the CEMS, or other emissions monitoring system approved for use under subpart HHH of this part, designed to interpret and convert individual output signals from pollutant concentration monitors, flow monitors, diluent gas monitors, and other component parts of the monitoring system to produce a continuous record of the measured parameters in the measurement units required by subpart HHH of this part.

Boiler means an enclosed fossil- or other-fuel-fired combustion device used to produce heat and to transfer heat to recirculating water, steam, or other medium.

Bottoming-cycle cogeneration unit means a cogeneration unit in which the energy input to the unit is first used to produce useful thermal energy and at least some of the reject heat from the useful thermal energy application or process is then used for power production.

CAIR designated representative means, for a CAIR source and each CAIR unit at the source, the natural person who is authorized by the owners and operators of the source and all CAIR units at the source, in accordance with subpart BBB of this part, to represent and legally bind each owner and operator in matters pertaining to the CAIR SO2 Trading Program and to the CAIR NOX Trading Program. This natural person shall be the same person who is the authorized account representative under the Acid Rain Program under § 72.20 of this chapter.

CAIR NOXTrading Program means a multi-state nitrogen oxides air pollution control and emission reduction program established by the Administrator in accordance with subparts AA through HH of this part and § 51.123 of this chapter, as a means of mitigating interstate transport of fine particulates, ozone, and nitrogen oxides.

CAIR permit means the legally binding and federally enforceable written document, or portion of such document, issued by the permitting authority under subpart CCC of this part, including any permit revisions, specifying the CAIR SO2 and NOX Trading Program requirements applicable to a CAIR source, to each CAIR unit at the CAIR source, and to the owners and operators and the CAIR designated representative of the CAIR source and each CAIR unit.

CAIR SO2allowance means a limited authorization issued by the Administrator under the Acid Rain Program to emit sulfur dioxide during the control period of the specified year for which the authorization is allocated or of any year thereafter under the CAIR SO2 Trading Program as follows:

(1) For one CAIR SO2 allowance allocated for a control period before 2010, one ton of sulfur dioxide;

(2) For two CAIR SO2 allowances allocated for a control period in 2010 through 2014, one ton of sulfur dioxide, provided that one such allowance alone authorizes zero tons of sulfur dioxide emissions under the CAIR SO2 Trading Program; and

(3) For 3 CAIR SO2 allowances allocated for a control period in 2015 or later, one ton of sulfur dioxide, provided that one or two such allowances alone authorize zero tons of sulfur dioxide emissions under the CAIR SO2 Trading Program.

CAIR SO2allowance deduction or deduct CAIR SO2allowances means the permanent withdrawal of CAIR SO2 allowances by the Administrator from a compliance account in order to account for a specified number of tons of sulfur dioxide emissions from all CAIR units at a CAIR source for a control period, determined in accordance with subparts FFF and HHH of this part, or to account for excess emissions.

CAIR SO2Allowance Tracking System (ISATS) means the system by which the Administrator records allocations, deductions, and transfers of CAIR SO2 allowances under the CAIR SO2 Trading Program.

CAIR SO2Allowance Tracking System account means an account in the CAIR SO2 Allowance Tracking System established by the Administrator for purposes of recording the allocation, holding, transferring, or deducting of CAIR SO2 allowances.

CAIR SO2allowance transfer deadline means midnight of March 1 or, if March 1 is not a business day, midnight of the first business day thereafter and is the deadline by which a CAIR SO2 allowance transfer must be submitted for recordation in a CAIR source's compliance account in order to meet the source's CAIR SO2 emissions limitation for the control period immediately preceding such deadline.

CAIR SO2allowances held or hold CAIR SO2allowances means the CAIR SO2 allowances recorded by the Administrator, or submitted to the Administrator for recordation, in accordance with subparts FFF and GGG of this part, in a CAIR SO2 Allowance Tracking System account.

CAIR SO2authorized account representative means a responsible natural person who is authorized, in accordance with subpart BBB of this part, to transfer and otherwise dispose of CAIR SO2 allowances held in a CAIR SO2 Allowance Tracking System general account; or, in the case of a compliance account, the CAIR designated representative of the source.

CAIR SO2emissions limitation means, for a CAIR source, the tonnage equivalent of the CAIR SO2 allowances available for compliance deduction for the source under § 96.254(a) and (b) in a control period.

CAIR SO2Trading Program means a multi-state sulfur dioxide air pollution control and emission reduction program established by the Administrator in accordance with subparts AAA through HHH of this part and § 51.124 of this chapter, as a means of mitigating interstate transport of fine particulates.

CAIR source means a source that includes one or more CAIR units.

CAIR unit means a unit that is subject to the CAIR SO2 Trading Program under § 96.204.

Clean Air Act means the Clean Air Act, 42 U.S.C. 7401, et seq., as amended by Pub. L. No. 101-549 (November 15, 1990).

Coal means any solid fuel classified as anthracite, bituminous, subbituminous, or lignite.

Coal-derived fuel means any fuel (whether in a solid, liquid, or gaseous state) produced by the mechanical, thermal, or chemical processing of coal.

Coal-fired means, with regard to a unit, combusting coal or any coal-derived fuel alone or in combination with any amount of any other fuel in any year.

Cogeneration unit means a unit:

(1) Having equipment used to produce electricity and useful thermal energy for industrial, commercial, heating, or cooling purposes through the sequential use of energy; and

(2) Producing during the 12-month period starting on the date the unit first produces electricity and during any calendar year after which the unit first produces electricity—

(i) For a topping-cycle cogeneration unit,

(A) Useful thermal energy not less than 5 percent of total energy output; and

(B) Useful power that, when added to one-half of useful thermal energy produced, is not less then 42.5 percent of total energy input or, if useful thermal energy produced is less than 15 percent of total energy output, not less than 45 percent of total energy input. Start Printed Page 32760

(ii) For a bottoming-cycle cogeneration unit, useful power not less than 45 percent of total energy input.

Combustion turbine means an enclosed device comprising a compressor, a combustor, and a turbine and in which the flue gas resulting from the combustion of fuel in the combustor passes through the turbine, rotating the turbine. A combustion turbine that is combined cycle also includes any associated heat recovery steam generator and steam turbine.

Commence commercial operation means, with regard to a unit that serves a generator, to have begun to produce steam, gas, or other heated medium used to generate electricity for sale or use, including test generation. Except as provided in § 96.205, for a unit that is a CAIR unit under § 96.204 on the date the unit commences commercial operation, such date shall remain the unit's date of commencement of commercial operation even if the unit is subsequently modified or reconstructed. Except as provided in § 96.205, for a unit that is not a CAIR unit under § 96.204 on the date the unit commences commercial operation, the date the unit becomes a CAIR unit under § 96.204 shall be the unit's date of commencement of commercial operation.

Commence operation means to have begun any mechanical, chemical, or electronic process, including, with regard to a unit, start-up of a unit's combustion chamber. Except as provided in § 96.205, for a unit that is a CAIR unit under § 96.204 on the date of commencement of operation, such date shall remain the unit's date of commencement of operation even if the unit is subsequently modified or reconstructed. Except as provided in § 96.205, for a unit that is not a CAIR unit under § 96.204 on the date of commencement of operation, the date the unit becomes a CAIR unit under § 96.204 shall be the unit's date of commencement of operation.

Common stack means a single flue through which emissions from two or more units are exhausted.

Compliance account means a CAIR SO2 Allowance Tracking System account, established by the Administrator for a CAIR source subject to an Acid Rain emissions limitations under § 73.31(a) or (b) of this chapter or for any other CAIR source under subpart FFF of this part, in which any CAIR SO2 allowance allocations under § 73.10 or part 74 of this chapter for the CAIR units at the source are initially recorded and in which are held CAIR SO2 allowances available for use for a control period in order to meet the source's CAIR SO2 emissions limitation.

Continuous emission monitoring system or CEMS means the equipment required under subpart HHH of this part to sample, analyze, measure, and provide, by means of readings recorded at least once every 15 minutes (using an automated data acquisition and handling system (DAHS)), a permanent record of sulfur dioxide (SO2) emissions, stack gas volumetric flow rate or stack gas moisture content (as applicable), in a manner consistent with part 75 of this chapter. The following systems are the principal types of continuous emission monitoring systems required under subpart HHH of this part:

(1) A flow monitoring system, consisting of a stack flow rate monitor and an automated DAHS. A flow monitoring system provides a permanent, continuous record of stack gas volumetric flow rate, in standard cubic feet per hour (scfh);

(2) A sulfur dioxide (SO2) monitoring system, consisting of a SO2 pollutant concentration monitor and an automated DAHS. An SO2 concentration monitoring system provides a permanent, continuous record of SO2 emissions, in parts per million (ppm);

(3) A moisture monitoring system, as defined in § 75.11(b)(2) of this chapter. A moisture monitoring system provides a permanent, continuous record of the stack gas moisture content, in percent H2 O (percent H2 O);

(4) A carbon dioxide (CO2) monitoring system, consisting of a CO2 pollutant concentration monitor (or an oxygen monitor plus suitable mathematical equations from which the CO2 concentration is derived) and the automated DAHS. A carbon dioxide monitoring system provides a permanent, continuous record of CO2 emissions, in percent CO2 (percent CO2); and

(5) An oxygen (O2) monitoring system, consisting of an O2 concentration monitor and an automated DAHS. An O2 monitoring system provides a permanent, continuous record of O2 in percent O2 (percent O2).

Control period means the period beginning January 1 of a year and ending on December 31 of the same year, inclusive.

Emissions means air pollutants exhausted from a unit or source into the atmosphere, as measured, recorded, and reported to the Administrator by the CAIR designated representative and as determined by the Administrator in accordance with subpart HHH of this part.

Energy Information Administration means the Energy Information Administration of the United States Department of Energy.

Excess emissions means any ton of sulfur dioxide emitted by the CAIR units at a CAIR source during a control period that exceeds the CAIR SO2 emissions limitation for the source.

Fossil fuel means natural gas, petroleum, coal, or any form of solid, liquid, or gaseous fuel derived from such material.

Fossil-fuel-fired means, with regard to a unit, any boiler or turbine combusting any amount of fossil fuel.

General account means a CAIR SO2 Allowance Tracking System account, established under subpart FFF of this part, that is not a compliance account.

Generator means a device that produces electricity.

Gross thermal energy means, with regard to a cogeneration unit, useful thermal energy output plus, where such output is made available for an industrial or commercial process, any heat contained in condensate return or makeup water.

Heat input means, with regard to a specified period to time, the product (in mmBtu/time) of the gross calorific value of the fuel (in Btu/lb) divided by 1,000,000 Btu/mmBtu and multiplied by the fuel feed rate into a combustion device (in lb of fuel/time), as measured, recorded, and reported to the Administrator by the CAIR designated representative and as determined by the Administrator in accordance with subpart HHH of this part. Heat input does not include the heat derived from preheated combustion air, recirculated flue gases, or exhaust from other sources.

Heat input rate means the amount of heat input (in mmBtu) divided by unit operating time (in hr) or, with regard to a specific fuel, the amount of heat input attributed to the fuel (in mmBtu) divided by the unit operating time (in hr) during which the unit combusts the fuel.

Life-of-the-unit, firm power contractual arrangement means a unit participation power sales agreement under which a customer reserves, or is entitled to receive, a specified amount or percentage of nameplate capacity and associated energy from any specified unit and pays its proportional amount of such unit's total costs, pursuant to a contract:

(1) For the life of the unit;

(2) For a cumulative term of no less than 30 years, including contracts that permit an election for early termination; or Start Printed Page 32761

(3) For a period no less than 25 years or 70 percent of the economic useful life of the unit determined as of the time the unit is built, with option rights to purchase or release some portion of the nameplate capacity and associated energy generated by the unit at the end of the period.

Maximum design heat input means the maximum amount of fuel per hour (in Btu/hr) that a unit is capable of combusting on a steady state basis, as specified by the manufacturer of the unit as of the initial installation of the unit.

Monitoring system means any monitoring system that meets the requirements of subpart HHH of this part, including a continuous emissions monitoring system or an alternative monitoring system.

Nameplate capacity means the maximum electrical generating output (in MWe) that a generator can sustain over a specified period of time when not restricted by seasonal or other deratings, as specified by the manufacturer of the generator as of the initial installation of the generator or, if the generator is subsequently modified or reconstructed resulting in an increase in such maximum electrical generating output, as specified by the person conducting the modification or reconstruction.

NOXBudget Trading Program means a multi-state nitrogen oxide air pollution control and emission reduction program established by air pollution control and emission reduction program established by the Administrator in accordance with subparts A through I of this part and § 51.121 of this chapter, as a means of mitigating interstate transport of ozone and nitrogen oxides.

Operator means any person who operates, controls, or supervises a CAIR unit or a CAIR source and shall include, but not be limited to, any holding company, utility system, or plant manager of such a unit or source.

Owner means any of the following persons:

(1) Any holder of any portion of the legal or equitable title in a CAIR unit; or

(2) Any holder of a leasehold interest in a CAIR unit; or

(3) Any purchaser of power from a CAIR unit under a life-of-the-unit, firm power contractual arrangement; provided that, unless expressly provided for in a leasehold agreement, owner shall not include a passive lessor, or a person who has an equitable interest through such lessor, whose rental payments are not based (directly or indirectly) on the revenues or income from the CAIR unit; or

(4) With respect to any general account, any person who has an ownership interest with respect to the CAIR SO2 allowances held in the general account and who is subject to the binding agreement for the CAIR authorized account representative to represent that person's ownership interest with respect to CAIR SO2 allowances.

Permitting authority means the State air pollution control agency, local agency, other State agency, or other agency authorized by the Administrator to issue or revise permits to meet the requirements of the CAIR SO2 Trading Program in accordance with subpart CCC of this part.

Potential electrical output capacity means 33 percent of a unit's maximum design heat input, divided by 3,413 mmBtu/kWh, divided by 1,000 kWh/MWh, and multiplied by 8,760 hr/yr.

Receive or receipt of means, when referring to the permitting authority or the Administrator, to come into possession of a document, information, or correspondence (whether sent in hard copy or by authorized electronic transmission), as indicated in an official correspondence log, or by a notation made on the document, information, or correspondence, by the permitting authority or the Administrator in the regular course of business.

Recordation, record, or recorded means, with regard to CAIR SO2 allowances, the movement of CAIR SO2 allowances by the Administrator into or between CAIR SO2 Allowance Tracking System accounts, for purposes of allocation, transfer, or deduction.

Reference method means any direct test method of sampling and analyzing for an air pollutant as specified in § 75.22 of this chapter.

Serial number means for a CAIR SO2 allowance, the unique identification number assigned to each CAIR SO2 allowance by the Administrator.

Sequential use of energy means:

(1) For a topping-cycle cogeneration unit, the use of reject heat from power production in a useful thermal energy application or process; or

(2) For a bottoming-cycle cogeneration unit, the use of reject heat from useful thermal energy application or process in power production.

Source means all buildings, structures, or installations located in one or more contiguous or adjacent properties under common control of the same person or persons. For purposes of § 502(c) of the Clean Air Act, a “source,” including a “source” with multiple units, shall be considered a single “facility.”

State means one of the 50 States or the District of Columbia that adopts the CAIR SO2 Trading Program pursuant to § 51.123 of this chapter.

Submit or serve means to send or transmit a document, information, or correspondence to the person specified in accordance with the applicable regulation:

(1) In person;

(2) By United States Postal Service; or

(3) By other means of dispatch or transmission and delivery. Compliance with any “submission,” “service,” or “mailing” deadline shall be determined by the date of dispatch, transmission, or mailing and not the date of receipt.

Title V operating permit means a permit issued under title V of the Clean Air Act and part 70 or part 71 of this chapter.

Title V operating permit regulations means the regulations that the Administrator has approved or issued as meeting the requirements of title V of the Clean Air Act and part 70 or 71 of this chapter.

Ton means 2,000 pounds. For the purpose of determining compliance with the CAIR SO2 emissions limitation, total tons of sulfur dioxide emissions for a control period shall be calculated as the sum of all recorded hourly emissions (or the mass equivalent of the recorded hourly emission rates) in accordance with subpart HHH of this part, with any remaining fraction of a ton equal to or greater than 0.50 tons deemed to equal one ton and any remaining fraction of a ton less than 0.50 tons deemed to equal zero tons.

Topping-cycle cogeneration unit means a cogeneration unit in which the energy input to the unit is first used to produce useful power and at least some of the reject heat from the power production is then used to provide useful thermal energy.

Total energy input means, with regard to a cogeneration unit, total energy of all forms supplied to the cogeneration unit, excluding energy produced by the cogeneration unit itself.

Total energy output means, with regard to a cogeneration unit, the sum of useful power and useful thermal energy produced by the cogeneration unit.

Unit means a stationary boiler or combustion turbine.

Unit operating day means a calendar day in which a unit combusts any fuel.

Unit operating hour or hour of unit operation means an hour in which a unit combusts any fuel.

Useful power means, with regard to a cogeneration unit, electricity or mechanical energy made available for use, excluding any such energy used in Start Printed Page 32762the power production process (which process includes, but is not limited to, any on-site processing or treatment of fuel combusted at the unit and any on-site emission controls).

Useful thermal energy means, with regard to a cogeneration unit, thermal energy that is:

(1) Made available to an industrial or commercial process, excluding any heat contained in condensate return or makeup water;

(2) Used in a heat application (e.g., space heating or domestic hot water heating); or

(3) Used in a space cooling application (i.e., thermal energy used by an absorption chiller).

Utility power distribution system means the portion of an electricity grid owned or operated by a distribution utility and dedicated to delivering electricity to customers.

Measurements, abbreviations, and acronyms.

Measurements, abbreviations, and acronyms used in this part are defined as follows:

Btu-British thermal unit.

CO2-carbon dioxide.

NOX-nitrogen oxide.

hr-hour.

kW-kilowatt electrical.

kWh-kilowatt hour.

mmBtu-million Btu.

MWe-megawatt electrical.

MWh-megawatt hour.

O2-oxygen.

SO2-sulfur dioxide.

yr-year.

Applicability.

The following units in a State shall be CAIR units, and any source that includes one or more such units shall be a CAIR source, subject to the requirements of this subpart and subparts BBB through HHH of this part:

(a) Except a unit under paragraph (b) of this section, a fossil fuel-fired boiler or combustion turbine serving at any time a generator with nameplate capacity of more than 25 MWe producing electricity for sale.

(b) A fossil fuel-fired cogeneration unit serving at any time a generator with nameplate capacity of more than 25 MWe and in any year supplying more than one-third of the unit's potential electric output capacity or 219,000 MWh, whichever is greater, to any utility power distribution system for sale.

Retired unit exemption.

(a) This section applies to any CAIR unit that is permanently retired.

(b)(1) Any CAIR unit that is permanently retired shall be exempt from the CAIR SO2 Trading Program, except for the provisions of this section, § 96.202, § 96.203, § 96.204, § 96.206(c)(5) through (8), § 96.207, and subparts EEE through GGG of this part.

(2) The exemption under paragraph (b)(1) of this section shall become effective the day on which the unit is permanently retired. Within 30 days of permanent retirement, the CAIR designated representative shall submit a statement to the permitting authority otherwise responsible for administering any CAIR permit for the unit. The CAIR designated representative shall submit a copy of the statement to the Administrator. The statement shall state, in a format prescribed by the permitting authority, that the unit was permanently retired on a specific date, and will comply with the requirements of paragraph (c) of this section.

(3) After receipt of the notice under paragraph (b)(2) of this section, the permitting authority will amend any permit under subpart CCC of this part covering the source at which the unit is located to add the provisions and requirements of the exemption under paragraphs (b)(1) and (c) of this section.

(c) Special provisions.

(1) A unit exempt under this section shall not emit any sulfur dioxide, starting on the date that the exemption takes effect.

(2) For a period of 5 years from the date the records are created, the owners and operators of a unit exempt under this section shall retain at the source that includes the unit, records demonstrating that the unit is permanently retired. The 5-year period for keeping records may be extended for cause, at any time prior to the end of the period, in writing by the permitting authority or the Administrator. The owners and operators bear the burden of proof that the unit is permanently retired.

(3) The owners and operators and, to the extent applicable, the CAIR designated representative of a unit exempt under this section shall comply with the requirements of the CAIR SO2 Trading Program concerning all periods for which the exemption is not in effect, even if such requirements arise, or must be complied with, after the exemption takes effect.

(4) A unit exempt under this section and located at a source that is required, or but for this exemption would be required, to have a title V operating permit shall not resume operation unless the CAIR designated representative of the source submits a complete CAIR permit application under § 96.222 for the unit not less than 18 months (or such lesser time provided by the permitting authority) before the later of January 1, 2010 or the date on which the unit resumes operation.

(5) On the earlier of the following dates, a unit exempt under paragraph (b) of this section shall lose its exemption:

(i) The date on which the CAIR designated representative submits a CAIR permit application under paragraph (c)(5) of this section;

(ii) The date on which the CAIR designated representative is required under paragraph (c)(5) of this section to submit a CAIR permit application; or

(iii) The date on which the unit resumes operation, if the CAIR designated representative is not required to submit a CAIR permit application for the unit.

(6) For the purpose of applying monitoring requirements under subpart HHH of this part, a unit that loses its exemption under this section shall be treated as a unit that commences operation and commercial operation on the first date on which the unit resumes operation.

Standard requirements.

(a) Permit Requirements.

(1) The CAIR designated representative of each CAIR source required to have a title V operating permit and each CAIR unit required to have a title V operating permit at the source shall:

(i) Submit to the permitting authority a complete CAIR permit application under § 96.222 in accordance with the deadlines specified in § 96.221(b) and (c); and

(ii) Submit in a timely manner any supplemental information that the permitting authority determines is necessary in order to review a CAIR permit application and issue or deny a CAIR permit.

(2) The owners and operators of each CAIR source required to have a title V operating permit and each CAIR unit required to have a title V operating permit at the source shall have a CAIR permit issued by the permitting authority and operate the unit in compliance with such CAIR permit.

(3) The owners and operators of a CAIR source that is not otherwise required to have a title V operating permit are not required to submit a CAIR permit application, and to have a CAIR permit, under subpart CCC of this part for such CAIR source.

(b) Monitoring requirements.

(1) The owners and operators and, to the extent applicable, the CAIR designated representative of each CAIR source and each CAIR unit at the source shall comply with the monitoring requirements of subpart HHH of this part. Start Printed Page 32763

(2) The emissions measurements recorded and reported in accordance with subpart HHH of this part shall be used to determine compliance by the unit with the CAIR SO2 emissions limitation under paragraph (c) of this section.

(c) Sulfur dioxide emission requirements.

(1) As of the CAIR SO2 allowance transfer deadline for a control period, the owners and operators of each CAIR source and each CAIR unit at the source shall hold, in the source's compliance account, a tonnage equivalent in CAIR SO2 allowances available for compliance deductions for the control period under § 96.254(a) not less than the total sulfur dioxide emissions for the control period from all CAIR units at the source, as determined in accordance with subpart HHH of this part.

(2) Each ton of sulfur dioxide emitted in excess of the CAIR SO2 emissions limitation shall constitute a separate violation of this subpart, the Clean Air Act, and applicable State law.

(3) A CAIR unit shall be subject to the requirements under paragraph (c)(1) of this section starting on the later of January 1, 2010 or the deadline for meeting the unit's monitor certification requirements under § 96.270(b)(1) or (b)(2).

(4) A CAIR SO2 allowance shall not be deducted, in order to comply with the requirements under paragraph (c)(1) of this section, for a control period in a year prior to the year for which the CAIR SO2 allowance was allocated.

(5) CAIR SO2 allowances shall be held in, deducted from, or transferred into or among CAIR SO2 Allowance Tracking System accounts in accordance with subparts FFF and GGG of this part.

(6) A CAIR SO2 allowance is a limited authorization to emit sulfur dioxide in accordance with the CAIR SO2 Trading Program. No provision of the CAIR SO2 Trading Program, the CAIR permit application, the CAIR permit, or exemption under § 96.205 and no provision of law shall be construed to limit the authority of the State or the United States to terminate or limit such authorization.

(7) A CAIR SO2 allowance does not constitute a property right.

(8) Upon recordation by the Administrator under subparts FFF and GGG of this part, every allocation, transfer, or deduction of a CAIR SO2 allowance to or from a CAIR unit's compliance account is incorporated automatically in any CAIR permit of the CAIR unit.

(d) Excess emissions requirements.

(1) The owners and operators of a CAIR unit that has excess emissions in any control period shall:

(i) Surrender the CAIR SO2 allowances required for deduction under § 96.254(d)(1); and

(ii) Pay any fine, penalty, or assessment or comply with any other remedy imposed under § 96.254(d)(2).

(e) Recordkeeping and Reporting Requirements.

(1) Unless otherwise provided, the owners and operators of the CAIR source and each CAIR unit at the source shall keep on site at the source each of the following documents for a period of 5 years from the date the document is created. This period may be extended for cause, at any time prior to the end of 5 years, in writing by the permitting authority or the Administrator.

(i) The certificate of representation under § 96.213 for the CAIR designated representative for the source and each CAIR unit at the source and all documents that demonstrate the truth of the statements in the certificate of representation; provided that the certificate and documents shall be retained on site at the source beyond such 5-year period until such documents are superseded because of the submission of a new certificate of representation under § 96.213 changing the CAIR designated representative.

(ii) All emissions monitoring information, in accordance with subpart HHH of this part; provided that to the extent that subpart HHH of this part provides for a 3-year period for recordkeeping, the 3-year period shall apply.

(iii) Copies of all reports, compliance certifications, and other submissions and all records made or required under the CAIR SO2 Trading Program.

(iv) Copies of all documents used to complete a CAIR permit application and any other submission under the CAIR SO2 Trading Program or to demonstrate compliance with the requirements of the CAIR SO2 Trading Program.

(2) The CAIR designated representative of a CAIR source and each CAIR unit at the source shall submit the reports required under the CAIR SO2 Trading Program, including those under subpart HHH of this part.

(f) Liability.

(1) Any person who knowingly violates any requirement or prohibition of the CAIR SO2 Trading Program, a CAIR permit, or an exemption under § 96.205 shall be subject to enforcement pursuant to applicable State or Federal law.

(2) Any person who knowingly makes a false material statement in any record, submission, or report under the CAIR SO2 Trading Program shall be subject to criminal enforcement pursuant to the applicable State or Federal law.

(3) No permit revision shall excuse any violation of the requirements of the CAIR SO2 Trading Program that occurs prior to the date that the revision takes effect.

(4) Each CAIR source and each CAIR unit shall meet the requirements of the CAIR SO2 Trading Program.

(5) Any provision of the CAIR SO2 Trading Program that applies to a CAIR source or the CAIR designated representative of a CAIR source shall also apply to the owners and operators of such source and of the CAIR units at the source.

(6) Any provision of the CAIR SO2 Trading Program that applies to a CAIR unit or the CAIR designated representative of a CAIR unit shall also apply to the owners and operators of such unit.

(g) Effect on Other Authorities. No provision of the CAIR SO2 Trading Program, a CAIR permit application, a CAIR permit, or an exemption under § 96.205 shall be construed as exempting or excluding the owners and operators and, to the extent applicable, the CAIR designated representative of a CAIR source or CAIR unit from compliance with any other provision of the applicable, approved State implementation plan, a federally enforceable permit, or the Clean Air Act.

Computation of time.

(a) Unless otherwise stated, any time period scheduled, under the CAIR SO2 Trading Program, to begin on the occurrence of an act or event shall begin on the day the act or event occurs.

(b) Unless otherwise stated, any time period scheduled, under the CAIR SO2 Trading Program, to begin before the occurrence of an act or event shall be computed so that the period ends the day before the act or event occurs.

(c) Unless otherwise stated, if the final day of any time period, under the CAIR SO2 Trading Program, falls on a weekend or a State or Federal holiday, the time period shall be extended to the next business day.

Appeal Procedures.

The appeal procedures for decisions of the Administrator under the CAIA SO2 Trading Program are set forth in part 78 of this chapter.

Subpart BBB—CAIR designated representative for CAIR sources
Authorization and responsibilities of CAIR designated representative.

(a) Except as provided under § 96.211, each CAIR source, including all CAIR Start Printed Page 32764units at the source, shall have one and only one CAIR designated representative, with regard to all matters under the CAIR SO2 Trading Program concerning the source or any CAIR unit at the source.

(b) The CAIR designated representative of the CAIR source shall be selected by an agreement binding on the owners and operators of the source and all CAIR units at the source and shall act in accordance with the certification statement in § 96.213(a)(5)(iv).

(c) Upon receipt by the Administrator of a complete certificate of representation under § 96.213, the CAIR designated representative of the source shall represent and, by his or her representations, actions, inactions, or submissions, legally bind each owner and operator of the CAIR source represented and each CAIR unit at the source in all matters pertaining to the CAIR SO2 Trading Program, notwithstanding any agreement between the CAIR designated representative and such owners and operators. The owners and operators shall be bound by any decision or order issued to the CAIR designated representative by the permitting authority, the Administrator, or a court regarding the source or unit.

(d) No CAIR permit will be issued, no emissions data reports will be accepted, and no CAIR SO2 Allowance Tracking System account will be established for a CAIR unit at a source, until the Administrator has received a complete certificate of representation under § 96.213 for a CAIR designated representative of the source and the CAIR units at the source.

(e)(1) Each submission under the CAIR SO2 Trading Program shall be submitted, signed, and certified by the CAIR designated representative for each CAIR source on behalf of which the submission is made. Each such submission shall include the following certification statement by the CAIR designated representative: “I am authorized to make this submission on behalf of the owners and operators of the source or units for which the submission is made. I certify under penalty of law that I have personally examined, and am familiar with, the statements and information submitted in this document and all its attachments. Based on my inquiry of those individuals with primary responsibility for obtaining the information, I certify that the statements and information are to the best of my knowledge and belief true, accurate, and complete. I am aware that there are significant penalties for submitting false statements and information or omitting required statements and information, including the possibility of fine or imprisonment.”

(2) The permitting authority and the Administrator will accept or act on a submission made on behalf of owner or operators of a CAIR source or a CAIR unit only if the submission has been made, signed, and certified in accordance with paragraph (e)(1) of this section.

Alternate CAIR designated representative.

(a) A certificate of representation may designate one and only one alternate CAIR designated representative, who may act on behalf of the CAIR designated representative. The agreement by which the alternate CAIR designated representative is selected shall include a procedure for authorizing the alternate CAIR designated representative to act in lieu of the CAIR designated representative.

(b) Upon receipt by the Administrator of a complete certificate of representation under § 96.213, any representation, action, inaction, or submission by the alternate CAIR designated representative shall be deemed to be a representation, action, inaction, or submission by the CAIR designated representative.

(c) Except in this section and §§ 96.202, 96.210(a), 96.212, 96.213, and 96.251, whenever the term “CAIR designated representative” is used in this subpart, the term shall be construed to include the alternate CAIR designated representative.

Changing CAIR designated representative and alternate CAIR designated representative; changes in owners and operators.

(a) Changing CAIR designated representative. The CAIR designated representative may be changed at any time upon receipt by the Administrator of a superseding complete certificate of representation under § 96.213. Notwithstanding any such change, all representations, actions, inactions, and submissions by the previous CAIR designated representative prior to the time and date when the Administrator receives the superseding certificate of representation shall be binding on the new CAIR designated representative and the owners and operators of the CAIR source and the CAIR units at the source.

(b) Changing alternate CAIR designated representative. The alternate CAIR designated representative may be changed at any time upon receipt by the Administrator of a superseding complete certificate of representation under § 96.213. Notwithstanding any such change, all representations, actions, inactions, and submissions by the previous alternate CAIR designated representative prior to the time and date when the Administrator receives the superseding certificate of representation shall be binding on the new alternate CAIR designated representative and the owners and operators of the CAIR source and the CAIR units at the source.

(c) Changes in owners and operators.

(1) In the event a new owner or operator of a CAIR source or a CAIR unit is not included in the list of owners and operators submitted in the certificate of representation under § 96.213, such new owner or operator shall be deemed to be subject to and bound by the certificate of representation, the representations, actions, inactions, and submissions of the CAIR designated representative and any alternate CAIR designated representative of the source or unit, and the decisions, orders, actions, and inactions of the permitting authority or the Administrator, as if the new owner or operator were included in such list.

(2) Within 30 days following any change in the owners and operators of a CAIR source or a CAIR unit, including the addition of a new owner or operator, the CAIR designated representative or alternate CAIR designated representative shall submit a revision to the certificate of representation under § 96.213 amending the list of owners and operators to include the change.

Certificate of representation.

(a) A complete certificate of representation for a CAIR designated representative or an alternate CAIR designated representative shall include the following elements in a format prescribed by the Administrator:

(1) Identification of the CAIR source and each CAIR unit at the source for which the certificate of representation is submitted.

(2) For each CAIR unit at the source, the dates on which the unit commenced operation and commenced commercial operation.

(3) The name, address, e-mail address (if any), telephone number, and facsimile transmission number (if any) of the CAIR designated representative and any alternate CAIR designated representative.

(4) A list of the owners and operators of the CAIR source and of each CAIR unit at the source.

(5) The following certification statements by the CAIR designated representative and any alternate CAIR designated representative—

(i) “I certify that I was selected as the CAIR designated representative or alternate CAIR designated Start Printed Page 32765representative, as applicable, by an agreement binding on the owners and operators of the source and each unit at the source.”

(ii) “I certify that I have all the necessary authority to carry out my duties and responsibilities under the CAIR SO2 and NOX Trading Programs on behalf of the owners and operators of the source and of each unit at the source and that each such owner and operator shall be fully bound by my representations, actions, inactions, or submissions.”

(iii) “I certify that the owners and operators of the source and of each unit at the source shall be bound by any order issued to me by the Administrator, the permitting authority, or a court regarding the source or unit.”

(iv) “Where there are multiple holders of a legal or equitable title to, or a leasehold interest in, a unit, or where a customer purchases power from a unit under life-of-the-unit, firm power contractual arrangements, I certify that: I have given a written notice of my selection as the ‘designated representative’ or ‘alternated designated representative’, as applicable, and of the agreement by which I was selected to each owner and operator of the source and of each unit at the source; and allowances and proceeds of transactions involving allowances will be deemed to be held or distributed in proportion to each holder's legal, equitable, leasehold, or contractual reservation or entitlement or, if such multiple holders have expressly provided for a different distribution of allowances by contract, that allowances and the proceeds of transactions involving allowances will be deemed to be held or distributed in accordance with the contract.”

(6) The signature of the CAIR designated representative and any alternate CAIR designated representative and the dates signed.

(b) Unless otherwise required by the permitting authority or the Administrator, documents of agreement referred to in the certificate of representation shall not be submitted to the permitting authority or the Administrator. Neither the permitting authority nor the Administrator shall be under any obligation to review or evaluate the sufficiency of such documents, if submitted.

Objections concerning CAIR designated representative.

(a) Once a complete certificate of representation under § 96.213 has been submitted and received, the permitting authority and the Administrator will rely on the certificate of representation unless and until a superseding complete certificate of representation under § 96.213 is received by the Administrator.

(b) Except as provided in § 96.212(a) or (b), no objection or other communication submitted to the permitting authority or the Administrator concerning the authorization, or any representation, action, inaction, or submission of the CAIR designated representative shall affect any representation, action, inaction, or submission of the CAIR designated representative or the finality of any decision or order by the permitting authority or the Administrator under the CAIR SO2 Trading Program.

(c) Neither the permitting authority nor the Administrator will adjudicate any private legal dispute concerning the authorization or any representation, action, inaction, or submission of any CAIR designated representative, including private legal disputes concerning the proceeds of CAIR SO2 allowance transfers.

Subpart CCC—Permits
General CAIR Trading Program permit requirements.

(a) For each CAIR source required to have a title V operating permit, such permit shall include a CAIR permit administered by the permitting authority for the title V operating permit. The CAIR portion of the title V permit shall be administered in accordance with the permitting authority's title V operating permits regulations promulgated under part 70 or 71 of this chapter, except as provided otherwise by this subpart.

(b) Each CAIR permit shall contain all applicable CAIR SO2 and NOX Trading Program requirements and shall be a complete and separable portion of the title V operating permit under paragraph (a) of this section.

Submission of CAIR permit applications.

(a) Duty to apply. The CAIR designated representative of any CAIR source required to have a title V operating permit shall submit to the permitting authority a complete CAIR permit application under § 96.222 by the applicable deadline in paragraph (b) of this section.

(b) Application deadline. For any source with any CAIR unit, the CAIR designated representative shall submit a complete CAIR permit application under § 96.222 covering such CAIR unit to the permitting authority at least 18 months (or such lesser time provided by the permitting authority) before the later of January 1, 2010 or the date on which the CAIR unit commences operation.

(c) Duty to Reapply. For a CAIR source required to have a title V operating permit, the CAIR designated representative shall submit a complete CAIR permit application under § 96.222 for the CAIR source covering the CAIR units at the source in accordance with the permitting authority's title V operating permits regulations addressing operating permit renewal.

Information requirements for CAIR permit applications.

A complete CAIR permit application shall include the following elements concerning the CAIR source for which the application is submitted, in a format prescribed by the permitting authority:

(a) Identification of the CAIR source, including plant name and the ORIS (Office of Regulatory Information Systems) or facility code assigned to the source by the Energy Information Administration, if applicable;

(b) Identification of each CAIR unit at the CAIR source; and

(c) The standard requirements under §§ 96.106 and 96.206.

CAIR permit contents and term.

(a) Each CAIR permit will contain, in a format prescribed by the permitting authority, all elements required for a complete CAIR permit application under § 96.222.

(b) Each CAIR permit is deemed to incorporate automatically the definitions of terms under § 96.202 and, upon recordation by the Administrator under subparts FFF and GGG of this part, every allocation, transfer, or deduction of a CAIR SO2 allowance to or from the compliance account of the CAIR source covered by the permit.

(c) The term of the CAIR permit will be set by the permitting authority, as necessary to facilitate coordination of the renewal of the CAIR permit with issuance, revision, or renewal of the CAIR source's title V permit.

CAIR permit revisions.

Except as provided in § 96.223(b), the permitting authority will revise the CAIR permit, as necessary, in accordance with the permitting authority's title V operating permits regulations addressing permit revisions.

Subpart DDD—[Reserved] Subpart EEE—[Reserved] Subpart FFF—CAIR SO2 Allowance Tracking System
CAIR SO2 Allowance Tracking System accounts.

(a) Nature and function of compliance accounts. Consistent with § 96.251(a), Start Printed Page 32766the Administrator will establish one compliance account for each CAIR source with one or more CAIR units. Deductions or transfers of CAIR SO2 allowances pursuant § 96.254, § 96.256, or subpart GGG of this part will be recorded in compliance accounts in accordance with this subpart.

(b) Nature and function of general accounts. Consistent with § 96.251(b), the Administrator will establish, upon request, a general account for any person. Transfers of CAIR SO2 allowances pursuant to subpart GGG of this part will be recorded in general accounts in accordance with this subpart.

Establishment of accounts.

(a) Compliance accounts. Upon receipt of a complete certificate of representation under § 96.213, the Administrator will establish a compliance account for the CAIR source for which the certificate of representation was submitted, unless the CAIR source is subject to an Acid Rain emissions limitation and already has a compliance account.

(b) General accounts.

(1) Application for general account.

(i) Any person may apply to open a general account for the purpose of holding and transferring CAIR SO2 allowances. An application for a general account may designate one and only one CAIR SO2 authorized account representative and one and only one alternate CAIR SO2 authorized account representative who may act on behalf of the CAIR SO2 authorized account representative. The agreement by which the alternate CAIR SO2 authorized account representative is selected shall include a procedure for authorizing the alternate CAIR SO2 authorized account representative to act in lieu of the CAIR SO2 authorized account representative.

(ii) A complete application for a general account shall be submitted to the Administrator and shall include the following elements in a format prescribed by the Administrator:

(A) Name, mailing address, e-mail address (if any), telephone number, and facsimile transmission number (if any) of the CAIR SO2 authorized account representative and any alternate CAIR SO2 authorized account representative;

(B) Organization name and type of organization, if applicable;

(C) A list of all persons subject to a binding agreement for the CAIR SO2 authorized account representative and any alternate CAIR SO2 authorized account representative to represent their ownership interest with respect to the allowances held in the general account;

(D) The following certification statement by the CAIR SO2 authorized account representative and any alternate CAIR SO2 authorized account representative: “I certify that I was selected as the CAIR SO2 authorized account representative or the CAIR SO2 alternate authorized account representative, as applicable, by an agreement that is binding on all persons who have an ownership interest with respect to allowances held in the general account. I certify that I have all the necessary authority to carry out my duties and responsibilities under the CAIR SO2 Trading Program on behalf of such persons and that each such person shall be fully bound by my representations, actions, inactions, or submissions and by any order or decision issued to me by the Administrator or a court regarding the general account.”

(E) The signature of the CAIR SO2 authorized account representative and any alternate CAIR SO2 authorized account representative and the dates signed.

(iii) Unless otherwise required by the permitting authority or the Administrator, documents of agreement referred to in the application for a general account shall not be submitted to the permitting authority or the Administrator. Neither the permitting authority nor the Administrator shall be under any obligation to review or evaluate the sufficiency of such documents, if submitted.

(2) Authorization of CAIR SO2authorized account representative. Upon receipt by the Administrator of a complete application for a general account under paragraph (b)(1) of this section:

(i) The Administrator will establish a general account for the person or persons for whom the application is submitted.

(ii) The CAIR SO2 authorized account representative and any alternate CAIR SO2 authorized account representative for the general account shall represent and, by his or her representations, actions, inactions, or submissions, legally bind each person who has an ownership interest with respect to CAIR SO2 allowances held in the general account in all matters pertaining to the CAIR SO2 Trading Program, notwithstanding any agreement between the CAIR SO2 authorized account representative or any alternate CAIR SO2 authorized account representative and such person. Any such person shall be bound by any order or decision issued to the CAIR SO2 authorized account representative or any alternate CAIR SO2 authorized account representative by the Administrator or a court regarding the general account.

(iii) Any representation, action, inaction, or submission by any alternate CAIR SO2 authorized account representative shall be deemed to be a representation, action, inaction, or submission by the CAIR SO2 authorized account representative.

(iv) Each submission concerning the general account shall be submitted, signed, and certified by the CAIR SO2 authorized account representative or any alternate CAIR SO2 authorized account representative for the persons having an ownership interest with respect to CAIR SO2 allowances held in the general account. Each such submission shall include the following certification statement by the CAIR SO2 authorized account representative or any alternate CAIR SO2 authorizing account representative: “I am authorized to make this submission on behalf of the persons having an ownership interest with respect to the CAIR SO2 allowances held in the general account. I certify under penalty of law that I have personally examined, and am familiar with, the statements and information submitted in this document and all its attachments. Based on my inquiry of those individuals with primary responsibility for obtaining the information, I certify that the statements and information are to the best of my knowledge and belief true, accurate, and complete. I am aware that there are significant penalties for submitting false statements and information or omitting required statements and information, including the possibility of fine or imprisonment.”

(v) The Administrator will accept or act on a submission concerning the general account only if the submission has been made, signed, and certified in accordance with paragraph (b)(2)(iv) of this section.

(3) Changing CAIR SO2authorized account representative and alternate CAIR SO2authorized account representative; changes in persons with ownership interest.

(i) The CAIR SO2 authorized account representative for a general account may be changed at any time upon receipt by the Administrator of a superseding complete application for a general account under paragraph (b)(1) of this section. Notwithstanding any such change, all representations, actions, inactions, and submissions by the previous CAIR SO2 authorized account representative prior to the time and date when the Administrator receives the superseding application for a general account shall be binding on the new CAIR SO2 authorized account Start Printed Page 32767representative and the persons with an ownership interest with respect to the CAIR SO2 allowances in the general account.

(ii) The alternate CAIR SO2 authorized account representative for a general account may be changed at any time upon receipt by the Administrator of a superseding complete application for a general account under paragraph (b)(1) of this section. Notwithstanding any such change, all representations, actions, inactions, and submissions by the previous alternate CAIR SO2 authorized account representative prior to the time and date when the Administrator receives the superseding application for a general account shall be binding on the new alternate CAIR SO2 authorized account representative and the persons with an ownership interest with respect to the CAIR SO2 allowances in the general account.

(iii)(A) In the event a new person having an ownership interest with respect to CAIR SO2 allowances in the general account is not included in the list of such persons in the application for a general account, such new person shall be deemed to be subject to and bound by the application for a general account, the representation, actions, inactions, and submissions of the CAIR SO2 authorized account representative and any alternate CAIR SO2 authorized account representative of the account, and the decisions, orders, actions, and inactions of the Administrator, as if the new person were included in such list.

(B) Within 30 days following any change in the persons having an ownership interest with respect to CAIR SO2 allowances in the general account, including the addition of persons, the CAIR SO2 authorized account representative or any alternate CAIR SO2 authorized account representative shall submit a revision to the application for a general account amending the list of persons having an ownership interest with respect to the CAIR SO2 allowances in the general account to include the change.

(4) Objections concerning CAIR SO2authorized account representative.

(i) Once a complete application for a general account under paragraph (b)(1) of this section has been submitted and received, the Administrator will rely on the application unless and until a superseding complete application for a general account under paragraph (b)(1) of this section is received by the Administrator.

(ii) Except as provided in paragraph (b)(3)(i) or (ii) of this section, no objection or other communication submitted to the Administrator concerning the authorization, or any representation, action, inaction, or submission of the CAIR SO2 authorized account representative or any alternative CAIR SO2 authorized account representative for a general account shall affect any representation, action, inaction, or submission of the CAIR SO2 authorized account representative or any alternative CAIR SO2 authorized account representative or the finality of any decision or order by the Administrator under the CAIR SO2 Trading Program.

(iii) The Administrator will not adjudicate any private legal dispute concerning the authorization or any representation, action, inaction, or submission of the CAIR SO2 authorized account representative or any alternative CAIR SO2 authorized account representative for a general account, including private legal disputes concerning the proceeds of CAIR SO2 allowance transfers.

(c) Account identification. The Administrator will assign a unique identifying number to each account established under paragraph (a) or (b) of this section.

Responsibilities of CAIR SO2 authorized account representative.

(a) Following the establishment of a CAIR SO2 Allowance Tracking System account, all submissions to the Administrator pertaining to the account, including, but not limited to, submissions concerning the deduction or transfer of CAIR SO2 allowances in the account, shall be made only by the CAIR SO2 authorized account representative for the account.

(b) Authorized account representative identification. The Administrator will assign a unique identifying number to each CAIR SO2 authorized account representative.

[Reserved]
Compliance with CAIR SO2 emissions limitation.

(a) CAIR SO2 allowance transfer deadline. The CAIR SO2 allowances are available to be deducted for compliance with a source's CAIR SO2 emissions limitation for a control period in a given year only if the CAIR SO2 allowances:

(1) Were allocated for the year or a prior year;

(2) Are held in the compliance account as of the CAIR SO2 allowance transfer deadline for the control period or are transferred into the compliance account by a CAIR SO2 allowance transfer correctly submitted for recordation under § 96.260 by the CAIR SO2 allowance transfer deadline for the control period; and

(3) Are not necessary for deduction for excess emissions for a prior control period under paragraph (d) of this section or for deduction under part 77 of this chapter.

(b) Deductions for compliance. Following the recordation, in accordance with § 96.261, of CAIR SO2 allowance transfers submitted for recordation in a source's compliance account by the CAIR SO2 allowance transfer deadline for a control period, the Administrator will deduct from the compliance account CAIR SO2 allowances available under paragraph (a) of this section in order to determine whether the source meets the CAIR SO2 emissions limitation for the control period as follows:

(1) For a CAIR source subject to an Acid Rain emissions limitation, the Administrator will, in the following order:

(i) Make the deductions required under §§ 73.35(b) and (c) of this part;

(ii) Make the deductions required under §§ 73.35(d) and 77.4 of this part; and

(iii) Treating the CAIR SO2 allowances deducted under paragraph (b)(1)(i) of this section as also being deducted under this paragraph (b)(1)(iii), deduct CAIR SO2 allowances until:

(A) The tonnage equivalent of the CAIR SO2 allowances deducted equals the number of tons of total sulfur dioxide emissions, determined in accordance with subpart HHH of this part, from all CAIR units at the source for the control period; or

(B) No more CAIR SO2 allowances available under paragraph (a) of this section and authorizing at least one ton of sulfur dioxide emissions remain in the compliance account.

(2) For a CAIR source not subject to an Acid Rain emissions limitation, the Administrator will deduct CAIR SO2 allowances until:

(i) The tonnage equivalent of the CAIR SO2 allowances deducted equals the number of tons of total sulfur dioxide emissions, determined in accordance with subpart HHH of this part, from all CAIR units at the source for the control period; or

(ii) No more CAIR SO2 allowances available under paragraph (a) of this section and authorizing at least one ton of sulfur dioxide emissions remain in the compliance account.

(c)(1) Identification of CAIR SO2allowances by serial number. The CAIR SO2 authorized account representative for a source's compliance account may request that specific CAIR SO2 allowances, identified by serial number, in the compliance account be deducted for emissions or excess emissions for a Start Printed Page 32768control period in accordance with paragraph (b) or (d) of this section. Such request shall be submitted to the Administrator by the allowance transfer deadline for the control period and include, in a format prescribed by the Administrator, the identification of the CAIR source and the appropriate serial numbers.

(2) First-in, first-out. The Administrator will deduct CAIR SO2 allowances under paragraph (b) or (d) of this section from the source's compliance account, in the absence of an identification or in the case of a partial identification of CAIR SO2 allowances by serial number under paragraph (c)(1) of this section, on a first-in, first-out (FIFO) accounting basis in the following order:

(i) Those CAIR SO2 allowances that were allocated to the units at the source under part 73 or 74 of this chapter, in the order of recordation; and then

(ii) Those CAIR SO2 allowances that were allocated to any unit and transferred and recorded in the compliance account pursuant to subpart GGG of this part, in the order of recordation.

(d) Deductions for excess emissions.

(1) After making the deductions for compliance under paragraph (b) of this section for a control period in which the CAIR source has excess emissions, the Administrator will deduct from the source's compliance account the tonnage equivalent in CAIR SO2 allowances, allocated for the year after such control period, of three times the number of tons of the source's excess emissions.

(2) Any allowance deduction required under paragraph (d)(1) of this section shall not affect the liability of the owners and operators of the CAIR source or the CAIR units at the source for any fine, penalty, or assessment, or their obligation to comply with any other remedy, for the same violation, as ordered under the Clean Air Act or applicable State law. The following guidelines will be followed in assessing fines, penalties or other obligations:

(i) For purposes of determining the number of days of violation, if a CAIR source has excess emissions for a control period, each day in the control period constitutes a day in vio