57356 Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations

ENVIRONMENTAL PROTECTION

AGENCY

40 CFR Parts 51, 72, 75, and 96

[FRL–6171–2]

RIN 2060–AH10

Finding of Significant Contribution and

Rulemaking for Certain States in the

Ozone Transport Assessment Group

Region for Purposes of Reducing

Regional Transport of Ozone

AGENCY: Environmental Protection

Agency (EPA).

ACTION: Final rule.

SUMMARY: In accordance with the Clean

Air Act (CAA), today’s action is a final

rule to require 22 States and the District

of Columbia to submit State

implementation plan (SIP) revisions to

prohibit specified amounts of emissions

of oxides of nitrogen (NOX)—one of the

precursors to ozone (smog) pollution—

for the purpose of reducing NOX and

ozone transport across State boundaries

in the eastern half of the United States.

Ground-level ozone has long been

recognized, in both clinical and

epidemiological research, to affect

public health. There is a wide range of

ozone-induced health effects, including

decreased lung function (primarily in

children active outdoors), increased

respiratory symptoms (particularly in

highly sensitive individuals), increased

hospital admissions and emergency

room visits for respiratory causes

(among children and adults with preexisting respiratory disease such as

asthma), increased inflammation of the

lung, and possible long-term damage to

the lungs.

In today’s action, EPA finds that

sources and emitting activities in each

of the 22 States and the District of

Columbia (23 jurisdictions) emit NOX in

amounts that significantly contribute to

nonattainment of the 1-hour and 8-hour

ozone national ambient air quality

standards (NAAQS), or will interfere

with maintenance of the 8-hour

NAAQS, in one or more downwind

States. Further, by today’s action, EPA

is requiring each of the affected upwind

jurisdictions (sometimes referred to as

upwind States) to submit SIP revisions

prohibiting those amounts of NOX

emissions which significantly

contribute to downwind air quality

problems. The reduction of those NOX

emissions will bring NOX emissions in

each of those States to within the

resulting statewide NOX emissions

budget levels established in today’s rule.

The 23 jurisdictions are: Alabama,

Connecticut, Delaware, District of

Columbia, Georgia, Illinois, Indiana,

Kentucky, Massachusetts, Maryland,

Michigan, Missouri, North Carolina,

New Jersey, New York, Ohio,

Pennsylvania, Rhode Island, South

Carolina, Tennessee, Virginia, West

Virginia, and Wisconsin. These States

will be able to choose any mix of

pollution-reduction measures that will

achieve the required reductions.

EFFECTIVE DATES: This rule is effective

December 28, 1998. The incorporation

by reference of certain publications

listed in the regulations is approved by

the Director of the Federal Register as of

December 28, 1998.

ADDRESSES: Dockets containing

information relating to this rulemaking

(Docket No. A–96–56 and Docket No.

A–9–35) are available for public

inspection at the Air and Radiation

Docket and Information Center (6102),

US Environmental Protection Agency,

401 M Street SW, room M–1500,

Washington, DC 20460, telephone (202)

260–7548, between 8:00 a.m. and 4:00

p.m., Monday through Friday, excluding

legal holidays. A reasonable fee may be

charged for copying.

FOR FURTHER INFORMATION CONTACT:

General questions concerning today’s

action should be addressed to Kimber S.

Scavo, Office of Air Quality Planning

and Standards, Air Quality Strategies

and Standards Division, MD–15,

Research Triangle Park, NC 27711,

telephone (919) 541–3354; e-mail:

scavo.kimber@epa.gov. Please refer to

SUPPLEMENTARY INFORMATION below for a

list of contacts for specific subjects

described in today’s action.

SUPPLEMENTARY INFORMATION:

Availability of Related Information

Documents related to the Ozone

Transport Assessment Group (OTAG)

are available on the Agency’s Office of

Air Quality Planning and Standards’

(OAQPS) Technology Transfer Network

(TTN) via the web at http://

www.epa.gov/ttn/. If assistance is

needed in accessing the system, call the

help desk at (919) 541–5384 in Research

Triangle Park, NC. Documents related to

OTAG can be downloaded directly from

OTAG’s webpage at http://

www.epa.gov/ttn/otag/. The OTAG’s

technical data are located at http://

www.iceis.mcnc.org/OTAGDC. The

notice of proposed rulemaking for this

final action, the supplemental notice of

proposed rulemaking, and associated

documents are located at http://epa.gov/

ttn/oarpg/otagsip.html. Information

related to Sections II, Weight of

Evidence Determination of Covered

States, and IV, Air Quality Assessment,

can be obtained in electronic form from

the following EPA website: http://

www.epa.gov/scram001/regmodcenter/

t28.htm. Information related to Section

III, Determination of Budgets, may be

found on the following EPA website:

http://www.epa.gov/capi. All

information in electronic form may also

be found on diskettes that have been

placed in the docket to this rulemaking.

For Additional Information

For technical questions related to the

air quality analyses, please contact

Norm Possiel; Office of Air Quality

Planning and Standards; Emissions,

Monitoring, and Analysis Division; MD–

14, Research Triangle Park, NC 27711,

telephone (919) 541–5692. For legal

questions, please contact Howard J.

Hoffman, Office of General Counsel, 401

M Street SW, MC–2344, Washington,

DC 20460, telephone (202) 260–5892.

For questions concerning the statewide

emissions budget revisions, please

contact Laurel Schultz; Office of Air

Quality Planning and Standards;

Emissions, Monitoring, and Analysis

Division; MD–14, Research Triangle

Park, NC 27711, telephone (919) 541–

5511. For questions concerning SIP

reporting requirements, please contact

Bill Johnson, Office of Air Quality

Planning and Standards, Air Quality

Strategies and Standards Division, MD–

15, Research Triangle Park, NC 27711,

telephone (919) 541–5245. For questions

concerning the model cap-and-trade

rule, please contact Rob Lacount, Office

of Atmospheric Programs, Acid Rain

Division, MC–6204J, 401 M Street SW,

Washington, DC 20460, telephone (202)

564–9122. For questions concerning the

regulatory cost analysis of electricity

generating sources, please contact Ravi

Srivastava, Office of Atmospheric

Programs, Acid Rain Division, MC–

6204J, 401 M Street SW, Washington DC

20460, telephone (202) 564–9093. For

questions concerning the regulatory cost

analysis of other stationary sources and

questions concerning the Regulatory

Impact Analysis (RIA), please contact

Scott Mathias, Office of Air Quality

Planning and Standards, Air Quality

Strategies and Standards Division, MD–

15, Research Triangle Park, NC 27711,

telephone (919) 541–5310.

Outline

I. Background

A. Summary of Rulemaking and Affected

States

B. General Factual Background

C. Statutory and Regulatory Background

1. CAA Provisions

a. 1970 and 1977 CAA Amendments

b. 1990 CAA Amendments

2. Regulatory Structure

a. March 2, 1995 Policy

b. OTAG
Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations 57357

c. EPA’s Transport SIP Call Regulatory

Efforts

d. Revision of the Ozone NAAQS

D. Section 126 Petitions

E. OTAG

F. Discussion of Comment Period and

Availability of Key Information

1. Request for Extension of the Comment

Period

2. Request for Time to Conduct Additional

Modeling

3. Availability of Key Information

4. Public Hearings

G. Implementation of Revised Air Quality

Standards

H. Summary of Major Changes between

Proposals and Final Rule

1. EPA’s Analytical Approach (Section

II.A)

2. Cost Effectiveness of Emissions

Reductions (Section II.D)

3. Determination of Budgets (Section III)

4. NOX Control Implementation and

Budget Achievement Dates (Section V)

5. SIP Criteria (Section VI.A)

6. Emissions Reporting Requirements for

States (Section VI.B)

7. NOX Budget Trading Program (Section

VII)

8. Interaction with Title IV NOX Rule

(Section VIII)

9. Administrative Requirements (Section

X)

II. EPA’s Analytical Approach

A. Interpretation of the CAA’s Transport

Provisions

1. Authority and Process for Requiring SIP

Submissions under the 1-Hour Ozone

NAAQS

a. Authority for Requiring SIP Submissions

under the 1-Hour NAAQS

b. Process for Requiring SIP Submissions

under the 1-Hour NAAQS

2. Authority and Process for Requiring SIP

Submissions under the 8-Hour Ozone

NAAQS

a. Authority for Requiring SIP Submissions

under the 8-Hour NAAQS

b. Process for Requiring SIP Submissions

under the 8-hour Standard

3. Requirements of Section 110(a)(2)(D)

a. Summary

b. Determination of Meaning of

‘‘Nonattainment’

c. Definition of Significant Contribution

d. Multi-factor Test for Determining

Significant Contribution

e. Air Quality Factors

f. Determination of Highly Cost-effective

Reductions and of Budgets

g. Other Considerations in Determination

of Significant Contribution

h. Interfere with Maintenance

i. Dates

j. Downwind Areas’ Control Obligations

k. Section 110(a)(2)(D) Caselaw

B. Alternative Interpretation of Section

110(a)(2)(D)

C. Weight-of-Evidence Determination of

Covered States

1. Major Findings from OTAG-Related

Technical Analyses

2. Summary of Notice of Proposed

Rulemaking Weight-of-Evidence

Approach

a. Quantification of Contributions

b. Evaluation of 1-Hour and 8-Hour

Contributions

c. Comments and Responses on Proposed

Weight-of-Evidence Approach to

Significant Contribution

3. Analysis of State-specific Air Quality

Factors

a. Overall Nature of Ozone Problem

(‘‘Collective Contribution’’)

b. Extent of Downwind Nonattainment

Problems

c. Air Quality Impacts of Upwind

Emissions on Downwind Nonattainment

4. Confirmation of States Making a

Contribution to Downwind

Nonattainment

a. Analysis Approach

b. States Which Contain Sources That

Significantly Contribute to Downwind

Nonattainment

c. Examples of Contributions From

Upwind States to Downwind

Nonattainment

d. Conclusions From Air Quality

Evaluation of Downwind Contributions

5. States Not Covered by This Rulemaking

D. Cost Effectiveness of Emissions

Reductions

1. Sources Included in the CostEffectiveness Determination

a. Electricity Generating Boilers and

Turbines

b. Other Stationary Sources

2. Sources Not Included in the CostEffectiveness Determination

a. Area Sources

b. Small Point Sources

c. Mobile Sources

d. Other Stationary Sources

e. Conclusion

E. Other Considerations

1. Consistency of Regional Reductions with

Attainment Needs of Downwind Areas

a. General Discussion

b. 8-hour Nonattainment Problems

c. Commenters’ Concerns

2. Equity Considerations

3. General Cost Considerations

4. Conclusion

III. Determination of Budgets

A. General Comments on the Base

Emission Inventory

1. Quality

2. Availability

B. Electricity Generating Units (EGUs)

1. Base Inventory

2. Growth

a. Growth Rates

b. Use of IPM

c. Use of ‘‘Corrected’’ Growth Rates

3. Budget Calculation

a. Input vs. Output

b. Alternative Emission Limits

c. Consideration of the Climate Change

Action Plan

C. Non-EGU Point Sources

1. Base Inventory

2. Growth

3. Budget Calculation

a. Proposed Control Assumptions

b. Small Source Exemption

c. Exemptions for Other Non-EGU Point

Sources

d. Sources Without Adequate Control

Information

e. Case-By-Case Analysis of Control

Measures

f. Cost Effectiveness

g. Industrial Boiler Control Costs

h. Cement Manufacturing

i. Stationary Internal Combustion Engines

j. Industrial Boilers and Turbines

k. Municipal Waste Combustors (MWCs)

D. Highway Mobile Sources

1. Base Inventory

2. Growth

3. Budget Calculation

a. I/M Program Coverage

b. Emissions Cap

c. Tier 2 Standards

d. Low Sulfur Fuel

e. Conformity

E. Stationary Area and Nonroad Mobile

Sources

1. Base Inventory

2. Growth

3. Budget Calculation

F. Other Budget Issues

1. Uniform vs. Regional Controls

2. Seasonal vs. Annual Controls

3. Full vs. Partial States

4. NOx Waivers

5. Recalculation of Budgets

6. Compliance Supplement Pool

a. Size of the Compliance Supplement Pool

b. State Distribution of the Compliance

Supplement Pool

7. Banking

a. Banking Starting in 2003

b. Management of Banked Allowances

c. Early Reduction Credits

G. Final Statewide Budgets

1. EGU

a. Description of Selected Approach

b. Summary of Budget Component

2. Non-EGU Point Sources

a. Description of Selected Approach

b. Summary of Budget Component

3. Mobile and Area Sources

a. Description of Selected Budget

Approach

b. Summary of Budget Component

4. Potential Alternatives to Meeting the

Budget

5. Statewide Budgets

IV. Air Quality Assessment

A. Assessment of Proposed Statewide

Budgets

B. Comments and Responses

C. Assessment of Alternative Control

Levels

1. Scenarios Modeled

2. Emissions for Model Runs

3. Modeling Results

a. Impacts of Alternative Controls

b. Impacts of Upwind Controls on

Downwind Nonattainment

c. Summary of Findings

V. NOx Control Implementation and Budget

Achievement Dates

A. NOx Control Implementation Date

1. Practicability

a. Combustion Controls

b. Post-Combustion Controls

2. Relationship to SIP Submittal Date

3. Rationale

B. Budget Achievement Date

VI. SIP Criteria and Emissions Reporting

Requirements

A. SIP Criteria

1. Schedule for SIP Revision

2. Approvability Criteria

a. Source Categories Subject to Additional

Approvability Criteria
57358 Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations

b. Pollution Abatement Requirements

c. Monitoring Requirements

d. Approvability of Trading Program

3. Sanctions

4. FIPs

B. Emissions Reporting Requirements for

States

1. Use of Inventory Data

2. Response to Comments

3. Final Rule

4. Data Elements to be Reported

5. 2007 Report

6. Ozone Season Reporting

7. Data Reporting Procedures

8. Confidential Data

C. Timeline

VII. NOX Budget Trading Program

A. General Background

B. NOX Budget Trading Program

Rulemaking Overview

C. General Design of NOX Budget Trading

Program

1. Appropriateness of Trading Program

2. Alternative Market Mechanisms

3. State Adoption of Model Rule

a. Process for Adoption

b. Model Rule Variations

4. Unrestricted Trading Market

a. Geographic Issues

b. Episodic Issues

D. Applicability

1. Core Sources

a. Commenters Who Felt the Core Group

Should Not Be Changed

b. Commenters Who Felt the Core Group

Should Be Expanded

c. Commenters Who Felt the Core Group Is

Overly Inclusive

2. Mobile/Area Sources

3. Monitoring

a. Use of Part 75 to Ensure Compliance

with the NOX Budget Trading Program

b. Use of CEMS on Large Units

c. Commenters Who do not Believe that

CEMS are Necessary

d. Issues Related to Monitoring and

Reporting Needed to Support a Heat

Input Allocation Methodology

e. Amendments to Part 75

E. Emission Limitations/Allowance

Allocations

1. Timing Requirements

2. Options for NOX Allowance Allocation

Methodology

3. New Source Set-Aside

4. Optional NOX Allocation Methodology

in Model Rule

F. Banking Provisions

1. Banking Starting in 2003

2. Management of Banked Allowances

3. Early Reduction Credits

4. Optional Methodology for Issuing Early

Reduction Credits

5. Integrating the OTC Program with the

NOX Budget Trading Program’s Banking

Provisions

G. New Source Review

VIII. Interaction with Title IV NOX Rule

IX. Non-Ozone Benefits of NOX Emissions

Decreases

A. Summary of Comments

B. Response to Comments

1. Drinking Water Nitrate

2. Eutrophication

3. Regulatory Impact Analysis

4. Justification for Rulemaking

X. Administrative Requirements

A. Executive Order 12866: Regulatory

Impact Analysis

B. Regulatory Flexibility Act: Small Entity

Impacts

C. Unfunded Mandates Reform Act

D. Paperwork Reduction Act

E. Executive Order 13045: Protection of

Children from Environmental Health

Risks and Safety Risks

1. Applicability of E.O. 13045

2. Children’s Health Protection

F. Executive Order 12898: Environmental

Justice

G. Executive Order 12875: Enhancing the

Intergovernmental Partnerships

H. Executive Order 13084: Consultation

and Coordination with Indian Tribal

Governments

I. Judicial Review

J. Congressional Review Act

K. National Technology Transfer and

Advancement Act

Appendix A—Detailed Discussion of

Changes to Part 75

CFR Revisions and Additions

Part 51

§ 51.121

§ 51.122

Part 72

Part 75

Part 96

I. Background

A. Summary of Rulemaking and

Affected States

By notice of proposed rulemaking

(NPR, proposal, or ‘‘proposed SIP call’’)

(62 FR 60318, November 7, 1997) and by

supplemental notice (SNPR or

supplemental proposal) (63 FR 25902,

May 11, 1998), EPA proposed to find

that NOX emissions from sources and

emitting activities (sources) in 23

jurisdictions (hereinafter also referred to

as States) will significantly contribute to

nonattainment of the 1-hour and 8-hour

ozone NAAQS, or will interfere with

maintenance of the 8-hour NAAQS, in

one or more downwind States

throughout the Eastern United States.

The EPA based these proposals on data

generated by OTAG, public comments,

and other relevant information. Today’s

final action confirms that proposed

finding. It also requires, under CAA

section 110(a)(1) and 110(k)(5), that the

23 jurisdictions adopt and submit SIP

revisions that, in order to assure that

their SIPs meet the requirements of

section 110(a)(2)(D)(i)(I), contain

provisions adequate to prohibit sources

in those States from emitting NOX in

amounts that ‘‘contribute significantly

to nonattainment in, or interfere with

maintenance by,’’ a downwind State.

The 23 jurisdictions are: Alabama,

Connecticut, Delaware, District of

Columbia, Georgia, Illinois, Indiana,

Kentucky, Massachusetts, Maryland,

Michigan, Missouri, North Carolina,

New Jersey, New York, Ohio,

Pennsylvania, Rhode Island, South

Carolina, Tennessee, Virginia, West

Virginia, and Wisconsin.

Each of these States and the District

of Columbia is required to adopt and

submit by September 30, 1999, a SIP

revision. The SIP revision must contain

measures that will assure that sources in

the State reduce their NOX emissions

sufficiently to eliminate the amounts of

NOX emissions that contribute

significantly to nonattainment, or that

interfere with maintenance, downwind.

By eliminating these amounts of NOX

emissions, the control measures will

assure that the remaining NOX

emissions will meet the level identified

in today’s rule as the State’s NOX

emissions budget. For simplicity, this

final rule may refer to the amounts that

such SIP provisions must prohibit in

order to meet the statute as the

‘‘significant amounts’’ of NOX

emissions. After prohibiting these

significant amounts of NOX, the

remaining amounts emitted by sources

in the covered States will not

‘‘significantly contribute to

nonattainment, or interfere with

maintenance by,’’ a downwind State,

under section 110(a)(2)(D)(i)(I). Section

II.C, Weight-of-Evidence Determination

of Covered States, describes how EPA

determined which States include

sources that emit NOX in amounts of

concern (the ‘‘covered’’ States), and

Sections II.D, Cost Effectiveness of

Emissions Reductions; II.E, Comparison

of Upwind and Downwind Costs; and

III, Determination of Budgets, describe

how EPA determined the significant

amounts of emissions and the resulting

statewide emissions budgets for the

States identified above. Section IV, Air

Quality Assessment, discusses air

quality analyses conducted by EPA

which help confirm the decisions and

requirements set forth in this

rulemaking. Section V, NOX Control

Implementation and Budget

Achievement Dates, primarily discusses

the dates by which (1) the States must

submit SIP revisions in response to

today’s action, (2) the sources must

implement the measures the States

choose for the purpose of prohibiting

the significant amounts of NOX, and (3)

the States are projected to achieve the

budget levels. Section VI, SIP Criteria

and Emissions Reporting Requirements,

describes the SIP requirements

themselves.

The SIP requirements permit each

State to determine what measures to

adopt to prohibit the significant

amounts and hence meet the necessary

emissions budget. Consistent with

OTAG’s recommendations to achieve
Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations 57359

NOX emissions decreases primarily from

large stationary sources in a trading

program, EPA encourages States to

consider electric utility and large boiler

controls under a cap-and-trade program

as a cost-effective strategy. The

recommended cap-and-trade program is

described in more detail in Section VII,

NOX Budget Trading Program. The EPA

also recognizes that promotion of energy

efficiency can contribute to a costeffective strategy. In Section VIII,

Interaction with Title IV NOX rule, EPA

explains that it is not adopting proposed

revisions to the title IV NOX rule

concerning the relationship between

this rulemaking and the title IV NOX

rule. The remaining parts of today’s

action include Section IX, Non-Ozone

Benefits of NOX Reductions, and

Section X, Administrative

Requirements.

The EPA also conducted a RIA which

is available in the docket to this

rulemaking as a technical support

document (TSD), entitled ‘‘Regulatory

Impact Analysis for the Regional NOX

SIP Call’’ (docket no. VI–B–09). A

detailed explanation of how EPA

calculated the budgets is also available

as a TSD entitled ‘‘Development of

Modeling Inventory and Budgets for the

Regional NOX SIP Call’’ (docket no. VI–

B–10). These two TSDs have been

revised for the final rulemaking. A

detailed explanation of the air quality

modeling analyses is also available,

entitled ‘‘Air Quality Modeling

Technical Support Document for the

Regional NOX SIP Call’’ (docket no. VI–

B–11) for this final rulemaking. This

preamble for today’s notice responds to

some of the comments, but another

document, entitled ‘‘Response to

Significant Comments on the Finding of

Significant Contribution and

Rulemaking for Certain States in the

OTAG Region for Purposes of Reducing

Regional Transport of Ozone,’’ is

included in the docket (docket no. VI–

C–01).

B. General Factual Background

In today’s action, EPA takes a

significant step toward reducing ozone

in the eastern half of the country.

Ground-level ozone, the main harmful

ingredient in smog, is produced in

complex chemical reactions when its

precursors, volatile organic compounds

(VOC) and NOX, react in the presence of

sunlight. The chemical reactions that

create ozone take place while the

pollutants are being blown through the

air by the wind, which means that

ozone can be more severe many miles

away from the source of emissions than

it is at the source.

The science of ozone formation,

transport, and accumulation is complex.

Ozone is produced and destroyed in a

cyclical set of chemical reactions

involving NOX, VOC and sunlight.

Emissions of NOX and VOC are

necessary for the formation of ozone in

the lower atmosphere. In part of the

cycle of reactions, ozone concentrations

in an area can be lowered by the

reaction of nitric oxide with ozone,

forming nitrogen dioxide; as the air

moves downwind and the cycle

continues, the nitrogen dioxide forms

additional ozone. The importance of

this reaction depends, in part, on the

relative concentrations of NOX, VOC

and ozone, all of which change with

time and location.

At ground level, ozone can cause a

variety of ill effects to human health,

crops and trees. Specifically, groundlevel ozone has been shown in clinical

and/or epidemiologial studies to have

the following health effects:

fl Decreased lung function, primarily in

children active outdoors

fl Increased respiratory symptoms,

particularly in highly sensitive individuals

fl Hospital admissions and emergency

room visits for respiratory causes among

children and adults with pre-existing

respiratory disease such as asthma

fl Inflammation of the lung

fl Possible long-term damage to the lungs

or even premature death.

The new 8-hour primary ambient air

quality standard (62 FR 38856, July 18,

1997) will provide increased protection

to the public from these health effects.

Each year, ground-level ozone above

background is also responsible for

significant agricultural crop yield losses.

Ozone also causes noticeable foliar

damage in many crops, trees, and

ornamental plants (i.e., grass, flowers,

shrubs, and trees) and causes reduced

growth in plants. Studies indicate that

current ambient levels of ozone are

responsible for damage to forests and

ecosystems (including habitat for native

animal species).

As part of the efforts to reduce

harmful levels of smog, EPA, today, is

establishing a requirement for certain

States to revise their SIPs in order to

implement the necessary regional-scale

reductions in NOX emissions, and,

thereby, reduce transported NOX and

ozone. Since air pollution travels across

county and State lines, it is essential for

State governments and air pollution

control agencies to cooperate to solve

the problem.

Currently, the following areas,

impacted by the 23 jurisdictions that are

the subject of today’s rulemaking, are

designated nonattainment areas for

ozone under the 1-hour NAAQS:

Atlanta, GA

Baltimore, MD

Birmingham, AL

Boston-Lawrence-Worcester (eastern MA),

MA–NH

Chicago-Gary-Lake County, IL–IN

Cincinnati-Hamilton, OH–KY

Door County, WI

Greater Connecticut

Kent & Queen Anne’s Counties, MD

Lancaster, PA

Louisville, KY–IN

Manitowoc County, WI

Milwaukee-Racine, WI

Muskegon, MI

New York-Northern New Jersey-Long Island,

NY–NJ–CT

Philadelphia-Wilmington-Trenton, PA–NJ–

DE–MD

Pittsburgh-Beaver Valley, PA

Portland, ME

Portsmouth-Dover-Rochester, NH

Providence (All RI), RI

St. Louis, MO–IL

Springfield (western MA), MA

Washington, DC–MD–VA

These areas include many of the

major urban centers in the eastern half

of the Nation. The combined population

for these areas is approximately 61.5

million. As described elsewhere, the

reductions called for in today’s action

will reduce ozone levels throughout

these areas.

Many more areas currently violate the

8-hour NAAQS. The EPA estimates that

a total population of approximately 73

million in the 23 jurisdictions live in

counties for which air quality is

monitored to be in violation of that

NAAQS. The reductions called for in

today’s action will reduce ozone levels

throughout these areas as well.

Moreover, as discussed below, many

of these areas are expected to be

classified as ‘‘transitional,’’ which

means, in most cases, that they are

expected to come into attainment solely

as a result of the reductions required by

today’s action. Thus, for those who live

in these areas, the reductions required

under today’s action, in-and-ofthemselves, are expected to mean the

difference between unhealthful ozone

levels and acceptable ozone levels.

Please note that EPA will not

designate ozone nonattainment areas for

the 8-hour NAAQS until 2000, and

these designations will be based on the

data that are most recently available at

that time.

C. Statutory and Regulatory Background

1. CAA Provisions

a. 1970 and 1977 CAA Amendments.

For almost 30 years, Congress has

focused major efforts on curbing

ground-level ozone. In 1970, Congress

amended the CAA to require, in title I,

that EPA issue, and periodically review
57360 Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations

1For moderate ozone nonattainment areas, the

attainment demonstration was due November 15,

1993 (section 182(b)(1)(A)), except that if the State

elected to conduct an urban airshed model, EPA

allowed an extension to November 15, 1994.

2 In addition, section 115 authorizes EPA to

require a SIP revision when one or more sources

within a State ‘‘cause or contribute to air pollution

which may reasonably be anticipated to endanger

public health or welfare in a foreign country.’’

and if necessary revise, NAAQS for

ubiquitous air pollutants (sections 108

and 109). Congress required the States

to submit SIPs to attain and maintain

those NAAQS, and Congress included,

in section 110, a list of minimum

requirements that SIPs must meet.

Congress anticipated that areas would

attain the NAAQS by 1975.

In 1977, Congress amended the CAA

by providing, among other things,

additional time for areas that were not

attaining the ozone NAAQS to do so, as

well as by imposing specific SIP

requirements for those nonattainment

areas. These provisions first required

the designation of areas as attainment,

nonattainment, or unclassifiable, under

section 107; and then required that SIPs

for ozone nonattainment areas include

the additional provisions set out in part

D of title I, as well as demonstrations of

attainment of the ozone NAAQS by

either 1982 or 1987 (section 172).

In addition, the 1977 Amendments

included two provisions focused on

interstate transport of air pollutants: the

predecessor to current section

110(a)(2)(D), which requires SIPs for all

areas to constrain emissions with

certain adverse downwind effects; and

section 126, which, in general,

authorizes a downwind State to petition

EPA to impose limits directly on

upwind sources found to adversely

affect that State. Section 110(a)(2)(D),

which is key to the present action, is

described in more detail below.

b. 1990 CAA Amendments. In 1990,

Congress amended the CAA to better

address, among other things, continued

nonattainment of the 1-hour ozone

NAAQS; the requirements that would

apply if EPA revised the 1-hour

standard; and transport of air pollutants

across State boundaries (Pub. L. 101–

549, Nov. 15, 1990, 104 Stat. 2399, 42

U.S.C., 7401–7671q). Numerous

provisions added, or revised, by the

1990 Amendments are relevant to

today’s proposal.

(1) 1-Hour Ozone NAAQS. In the 1990

Amendments, Congress required the

States and EPA to review and, if

necessary, revise the designation of

areas as attainment, nonattainment, and

unclassifiable under the ozone NAAQS

in effect at that time, which was the 1-

hour standard (section 107(d)(4)). Areas

designated as nonattainment were

divided into, primarily, five

classifications based on air quality

design values (section 181(a)(1)). Each

classification carries specific

requirements, including new attainment

dates (sections 181–182). In increasing

severity of the air quality problem, these

classifications are marginal, moderate,

serious, severe and extreme. The OTAG

region includes nonattainment areas of

all classifications except extreme.

As amended in 1990, the CAA

requires States containing ozone

nonattainment areas classified as

moderate or above to submit several SIP

revisions at various times. One set of

SIP revisions included specified control

measures, such as reasonably available

control technology (RACT) for existing

VOC and NOX sources (section

182(b)(2), 182(f)). In addition, the CAA

requires the reduction of VOC in the

amount of 15 percent by 1996 from a

1990 baseline (section 182(b)(1)).

Further, for nonattainment areas

classified as serious and above, the CAA

requires the reduction of VOC or NOX

emissions in the amount of 9 percent

over each 3-year period from 1996

through the attainment date (the rate-ofprogress (ROP) SIP submittals), under

section 182(c)(2)(B). In addition, the

CAA requires a demonstration of

attainment, including air quality

modeling, for the nonattainment area

(the attainment demonstration), as well

as SIP measures containing any

additional reductions that may be

necessary to attain by the applicable

attainment date (section 182(c)-(e)). The

CAA established November 15, 1994 as

the required date for the ROP and

attainment demonstration SIP

submittals for areas classified as serious

and above.1

(2) Revised NAAQS. Section 109(d) of

the CAA requires periodic review and,

if appropriate, revision of the NAAQS.

As amended in 1990, the CAA further

requires EPA to designate areas as

attainment, nonattainment, and

unclassifiable under a revised NAAQS

(section 107(d)(1); section 6103, Pub. L.

105–178). The CAA authorizes EPA to

classify areas that are designated

nonattainment under the new NAAQS

and to establish for those areas

attainment dates that are as

expeditiously as practicable, but not to

exceed 10 years from the date of

designation (section 172(a)).

(3) General Requirements. The CAA

continues, in revised form, certain

requirements, dating from the 1970

Amendments, which pertain to all areas,

regardless of their designation. All areas

are required to submit SIPs within

certain timeframes (section 110(a)(1)),

and those SIPs must include specified

provisions, under section 110(a)(2). In

addition, SIPs for nonattainment areas

are generally required to include

additional specified control

requirements, as well as controls

providing for attainment of any revised

NAAQS and periodic reductions

providing ‘‘reasonable further progress’’

in the interim (section 172(c)).

(4) Provisions Concerning Transport

of Ozone and Its Precursors. The 1990

Amendments reflect general awareness

by Congress that ozone is a regional, and

not merely a local, problem. As

described above, ozone and its

precursors may be transported long

distances across State lines to combine

with ozone and precursors downwind,

thereby exacerbating the ozone

problems downwind. The phenomenon

of ozone transport was not generally

recognized until relatively recently. Yet,

ozone transport is a major reason for the

persistence of the ozone problem,

notwithstanding the imposition of

numerous controls, both Federal and

State, across the country.

Section 110(a)(2)(D) provides one of

the most important tools for addressing

the problem of transport. This

provision, which applies by its terms to

all SIPs for each pollutant covered by a

NAAQS, and for all areas regardless of

their attainment designation, provides

that a SIP must contain adequate

provisions prohibiting its sources from

emitting air pollutants in amounts that

will contribute significantly to

nonattainment, or interfere with

maintenance, in one or more downwind

States.

Section 110(k)(5) authorizes EPA to

find that a SIP is substantially

inadequate to meet any CAA

requirement. If EPA makes such a

finding, it must require the State to

submit, within a specified period, a SIP

revision to correct the inadequacy.

The CAA further addresses interstate

transport of pollution in section 126,

which Congress revised slightly in 1990.

Subsection (b) of that provision

authorizes each State (or political

subdivision) to petition EPA for a

finding designed to protect that entity

from upwind sources of air pollutants.2

In addition, the 1990 Amendments

added section 184, which delineates a

multistate ozone transport region (OTR)

in the Northeast, requires specific

additional controls for all areas (not

only nonattainment areas) in that

region, and establishes the Ozone

Transport Commission (OTC) for the

purpose of recommending to EPA

regionwide controls affecting all areas in

that region. At the same time, Congress

added section 176A, which authorizes
Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations 57361

3 Guidance for Implementing the 1-hour Ozone

and Pre-Existing PM10 NAAQS, Memorandum from

Richard D. Wilson, dated December 29, 1997.

the formation of transport regions for

other pollutants and in other parts of the

country.

2. Regulatory Structure

a. March 2, 1995 Policy.

Notwithstanding significant efforts, the

States generally were not able to meet

the November 15, 1994 statutory

deadline for the attainment

demonstration and ROP SIP

submissions required under section

182(c). The major reason for this failure

was that at that time, States with

downwind nonattainment areas were

not able to address transport from

upwind areas. As a result, in a

memorandum from Mary D. Nichols,

Assistant Administrator for Air and

Radiation, dated March 2, 1995, entitled

‘‘Ozone Attainment Demonstrations,’’

(March 2, 1995 Memorandum or the

Memorandum), EPA recognized the

efforts made by States and the

remaining difficulties in making the

ROP and attainment demonstration

submittals. The EPA recognized that

development of the necessary technical

information, as well as the control

measures necessary to achieve the large

level of reductions likely to be required,

had been particularly difficult for the

States affected by ozone transport.

Accordingly, as an administrative

remedial matter, the Memorandum

indicated that EPA would establish new

timeframes for SIP submittals. The

Memorandum indicated that EPA would

divide the required SIP submittals into

two phases. Phase I generally consisted

of (i) SIP measures providing for ROP

reductions due by the end of 1999, (ii)

an enforceable SIP commitment to

submit any remaining required ROP

reductions on a specified schedule after

1996, and (iii) an enforceable SIP

commitment to submit the additional

SIP measures needed for attainment.

Phase II consists of the remaining

submittals, beginning in 1997.

The Phase II submittals primarily

consisted of the remaining ROP SIP

measures, the attainment demonstration

and additional rules needed to attain,

and any regional controls needed for

attainment by all areas in the region.

The March 2, 1995 Memorandum

indicated that the attainment

demonstration, target calculations for

the post-1999 ROP milestones, and

identification of rules needed to attain

and for post-1999 ROP were due in mid1997. To allow time for States to

incorporate the results of the OTAG

modeling into their local plans, EPA

extended the mid-1997 submittal date to

April 1998.3

b. OTAG. In addition, the March 2,

1995 Memorandum called for an

assessment of the ozone transport

phenomenon. The Environmental

Council of the States (ECOS) had

recommended formation of a national

work group to allow for a thoughtful

assessment and development of

consensus solutions to the problem. The

OTAG was a partnership between EPA,

the 37 easternmost States and the

District of Columbia, industry

representatives, and environmental

groups. The OTAG’s air quality

modeling and recommendations formed

the basis for today’s action.

c. EPA’s Transport SIP Call

Regulatory Efforts. Shortly after OTAG

began its work, EPA began to indicate

that it intended to issue a SIP call to

require States to implement the

reductions necessary to address the

ozone transport problem. On January 10,

1997 (62 FR 1420), EPA published a

notice of intent that articulated this goal

and indicated that before taking final

action, EPA would carefully consider

the technical work and any

recommendations of OTAG. The EPA

published the NPR for the NOX SIP call

by notice dated November 7, 1997 (62

FR 60319). The NPR proposed to make

a finding of significant contribution due

to transported NOX emissions to

nonattainment or maintenance problems

downwind and to assign NOX emissions

budgets for 23 jurisdictions. The EPA

published a supplemental notice of

proposed rulemaking (SNPR) by notice

dated May 11, 1998 (63 FR 25902)

which proposed a model NOX budget

trading program and State reporting

requirements and provided the air

quality analyses of the proposed

statewide NOX emissions budgets. The

EPA received approximately 700

comments on these proposals. The

comment periods are described in

Section I.F, Discussion of Comment

Period and Availability of Key

Information. Throughout the course of

the rulemaking, EPA has added

information to the docket. By notice

dated August 24, 1998 (63 FR 45032),

EPA published a notice of availability

listing the additional documents placed

in the docket.

d. Revision of the Ozone NAAQS. On

July 18, 1997 (62 FR 38856), EPA issued

its final action to revise the NAAQS for

ozone. The EPA’s decision to revise the

standard was based on the Agency’s

review of the available scientific

evidence linking exposures to ambient

ozone to adverse health and welfare

effects at levels allowed by the preexisting 1-hour ozone standards. The 1-

hour primary standard was replaced by

an 8-hour standard at a level of 0.08

parts per million (ppm), with a form

based on the 3-year average of the

annual fourth-highest daily maximum 8-

hour average ozone concentration

measured at each monitor within an

area. The new primary standard will

provide increased protection to the

public, especially children and other atrisk populations, against a wide range of

ozone-induced health effects. Health

effects are described in paragraph I.B,

General Factual Background. The EPA

retained the applicability of the 1-hour

NAAQS for existing nonattainment

areas until such time as EPA determines

that an area has attained the 1-hour

NAAQS (40 CFR 50.9(b)).

The pre-existing 1-hour secondary

ozone standard was replaced by an 8-

hour standard identical to the new

primary standard. The new secondary

standard will provide increased

protection to the public welfare against

ozone-induced effects on vegetation.

D. Section 126 Petitions

In a separate rulemaking, EPA is

proposing action on petitions submitted

by eight northeastern States under

section 126 of the CAA. Each petition

specifically requests that EPA make a

finding that NOX emissions from certain

major stationary sources significantly

contribute to ozone nonattainment

problems in the petitioning State. The

eight States are Connecticut,

Massachusetts, Maine, New Hampshire,

New York, Pennsylvania, Rhode Island,

and Vermont.

Both the NOX SIP call and the section

126 petitions are designed to address

ozone transport through reductions in

upwind NOX emissions. However, the

EPA’s response to the section 126

petitions differs from EPA’s action in

the NOX SIP call rulemaking in several

ways. In today’s NOX SIP call, EPA is

determining that certain States are or

will be significantly contributing to

nonattainment or maintenance problems

in downwind States. The EPA is

requiring the upwind States to submit

SIP provisions to reduce the amounts of

each State’s NOX emissions that

significantly contribute to downwind air

quality problems. The States will have

the discretion to select the mix of

control measures to achieve the

necessary reductions. By contrast, under

section 126, if findings of significant

contribution are made for any sources

identified in the petitions, EPA would

determine the necessary emissions
57362 Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations

4The eight northeastern States that filed section

126 petitions also filed suit in the District Court for

the Southern District of New York, to compel EPA

to take action on those petitions within prescribed

periods. State of Connecticut v. Browner, No. 98–

1376 (S.D.N.Y., filed Feb. 25, 1998). The EPA and

the eight northeastern States jointly filed a motion

to enter a consent order prescribing certain dates for

EPA action.

limits to address the amount of

significant contribution and would

directly regulate the sources. A section

126 remedy would apply only to

sources in States named in the petitions.

Based on the view that the SIP call

and section 126 petitions are both

designed to achieve the same goal,

several commenters urged EPA to

coordinate the two actions to the

maximum extent possible. The EPA

agrees that the two actions are closely

related and, therefore, should be

coordinated. This will help provide

certainty for State and business

planning requirements. In addition, this

coordination can help to facilitate a

trading program among sources in SIP

call States that choose to participate in

the NOX trading program, and any

section 126 sources that would be

subject to a Federal NOX trading

program.

The section 126 provisions require

that any control remedy be

implemented within 3 years from the

date of the finding that major sources or

a group of stationary sources emit or

would emit in violation of the relevant

prohibition in section 110(a)(2)(D).

Under EPA’s anticipated rulemaking

schedule 4 on the petitions, the

compliance date for sources for which

EPA makes such a finding could be

April 30, 2002; November 30, 2002; or

May 1, 2003. Several commenters

expressed concern that the compliance

deadline under section 126 was driving

EPA’s decision on the compliance

deadline for the NOX SIP call.

Therefore, they believed that no changes

would be made in the proposed NOX

SIP call deadline in response to

comments.

While EPA believes it is advantageous

to coordinate the section 126 and NOX

SIP call actions, EPA disagrees that this

constrains EPA from being responsive to

public comments and considering

alternative compliance dates. See

discussion below in Section V, NOX

Control Implementation and Budget

Attainment Dates.

In the NOX SIP call NPR, EPA

proposed that States be required to

submit SIPs within 12 months of the

final SIP call. One commenter asserted

that the timing and terms of the

rulemaking schedule for the section 126

petitions precludes EPA from

considering public comments

advocating different SIP due dates for

the NOX SIP call. The section 126

rulemaking schedule provides several

options. One option would allow

findings on the petitions to be deferred

pending certain actions by the States

and EPA on State submittals in response

to the NOX SIP call. The premise for the

specified schedule is that the SIP due

date would be September 30, 1999 (i.e.,

roughly 12 months from signature of the

notice on the final NOX SIP call). As

discussed below in Section VI, SIP

Revision Criteria and Schedule, EPA

continues to believe 12 months is an

appropriate timeframe. However, had

EPA determined that a longer timeframe

for SIP submittal was warranted, the

section 126 rulemaking schedule would

not have restricted EPA from

establishing a later due date.

One commenter supported the section

126 rulemaking schedule because they

thought it had the effect of using the SIP

process rather than the source-based

petitions in that it provides an option of

deferring section 126 findings if EPA

approves a State’s NOX SIP. Another

commenter thought that the conditions

for deferring section 126 findings were

too stringent, and, therefore, section 126

would inevitably be triggered prior to

approval of any SIP provisions. This

issue is discussed in detail in Section

II.A.2.c. in the NPR EPA just issued on

the section 126 petitions, which appears

in the docket.

E. OTAG

As discussed in the proposed SIP call,

OTAG completed the most

comprehensive analyses of ozone

transport ever conducted. The EPA

participated extensively in this process.

The EPA believes that the OTAG

process was successful and generated

much useful technical and modeling

information on regional ozone transport.

This information provided EPA with the

foundation for this rulemaking.

The EPA received numerous

comments regarding the relationship

between the OTAG recommendations

and EPA’s proposed SIP call. Some

commenters asserted that the Agency’s

proposal was inconsistent with the

OTAG recommendations, while others

believed that EPA used the information

and recommendations from OTAG

appropriately. Primarily, commenters

stated that OTAG recommended a range

of controls for utility sources instead of

a uniform level of control for all of the

included States.

The OTAG did recommend

consideration of a range of controls, and

although it did not specifically

recommend uniform controls across a

broad region, such a control scheme is

within the range of its recommendation.

The EPA’s action today is based on its

consideration of OTAG’s

recommendations, as well as

information resulting from EPA’s

additional work, and extensive public

input generated through notice-andcomment rulemaking. The EPA

continues to believe, for reasons

explained in Section III.F.1, Uniform vs.

Regional Controls, that requiring NOX

emissions reductions across the region

in amounts achievable by uniform

controls is a reasonable, cost-effective

step to take at this time to mitigate

ozone nonattainment in downwind

States for both the 1-hour and 8-hour

standards.

Commenters also stated that EPA

applied an electric utility control level

that was more stringent than the upper

limit of the OTAG range of utility

controls. The OTAG recommended a

range of utility controls that falls

between specific CAA-required controls

and the less stringent of 85 percent

reduction from the 1990 rate (lb/

mmBtu), or 0.15 lb/mmBtu. In

determining the appropriate level of

emissions reductions, EPA considered

what levels of NOX reductions could be

obtained by applying, to various source

sectors, controls that are among the

most cost effective and feasible with

today’s proven pollution control

technologies. The EPA chose emissions

reductions that are equivalent to an

emission limit from utilities of 0.15 lb/

mmBtu. The EPA acknowledges that

this level may be more protective than

the most protective level contained in

the OTAG recommendation in some

cases, but, as discussed below in

Section IV, Air Quality Assessment,

EPA believes that it provides the most

improvement in air quality while

staying within the bounds of the most

highly cost-effective technology

available. (Cost effectiveness is

discussed in Section II.D.) In addition,

by relying on actual 1995–1996

continuous emission monitoring data,

rather than relying on estimated 1990

emission data, this approach provides a

more accurate way of determining the

States’ budgets since it minimizes any

chances of over-or under-estimation of

emissions.

Commenters asserted that OTAG

recommended 12 months for additional

modeling—especially subregional

modeling—before promulgating the SIP

call; and these commenters expressed

concern that EPA did not provide this

amount of time following publication of

the NPR. As discussed in more detail in

Section I.F, Discussion of Comment

Period and Availability of Key
Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations 57363

5Ozone Transport Assessment Group Policy

Paper approved by the Policy Group on December

4, 1995.

6The OTAG recommendations are located in

Appendix B of the November 7, 1997 NPR (62 FR

60376).

7Letter to the Honorable Ken Calvert, Chairman,

Subcommittee on Energy and Environment, U.S.

House of Representatives, from Robert D. Brenner,

Acting Deputy Assistant Administrator for Air and

Radiation, U.S. EPA, June 26, 1998, transmitting

EPA’s responses to questions following the May 20,

1998 congressional hearing on EPA’s proposed rule

on paints and coatings.

Information, the Agency ultimately

provided approximately 1 year from the

conclusion of OTAG for States and other

members of the public to complete and

submit subregional and other types of

modeling. The EPA has considered this

additional modeling in finalizing

today’s rule.

Some commenters stated that the goal

of OTAG was to address attainment of

the ozone NAAQS. This is incorrect.

The OTAG’s goal was to reduce ozone

transport, which is one of the steps

necessary to enable attainment; the goal

was not to recommend an overall

strategy that would yield attainment

through regional measures alone. The

OTAG articulated its overall goal as

follows:

* * * identify and recommend a strategy

to reduce transported ozone and its

precursors which, in combination with other

measures, will enable attainment and

maintenance of the national ambient ozone

standard in the OTAG region. A number of

criteria will be used to select the strategy

including, but not limited to, cost

effectiveness, feasibility, and impacts on

ozone levels.5

It is also EPA’s goal to ensure that

sufficient regional reductions are

achieved to mitigate ozone transport in

the eastern half of the United States and

thus, in conjunction with local controls,

enable nonattainment areas to attain and

maintain the ozone NAAQS.

Commenters indicated that OTAG

focused only on the 1-hour standard

nonattainment problem and did not

assess compliance implications of the 8-

hour standard. For this reason,

according to commenters, EPA should

not base today’s action on the

nonattainment of the 8-hour NAAQS. It

is true that OTAG was established to

address transport issues associated with

meeting the 1-hour standard. The EPA

did not promulgate the 8-hour standard

until shortly after OTAG concluded;

thus, OTAG did not recommend

strategies to address the 8-hour NAAQS.

However, because EPA had proposed an

8-hour standard, OTAG did examine the

impacts of different strategies on 8-hour

average ozone predictions.

In light of OTAG’s work and

additional information, EPA is able to

assess ozone transport as it relates to the

8-hour NAAQS and to set forth

requirements as necessary to address the

8-hour standard in this rulemaking.

Ozone transport causes problems for

downwind areas under either the 1-hour

or 8-hour standard. The regional

reductions of NOX that will be achieved

through this SIP call for the 1-hour

NAAQS are key components for meeting

the new 8-hour ozone standard in a

cost-effective manner. Therefore, EPA

believes that the OTAG

recommendations for how to address

ozone transport are valid for both

NAAQS.

Several commenters urged EPA to

adopt and implement all Federal

measures identified in the OTAG

recommendations.6 The Agency is

committed to continue implementing

national control measures for NOX, as

recommended by OTAG. In addition,

EPA has adopted the following national

measures for purposes of reducing VOC:

architectural and industrial

maintenance coatings, consumer/

commercial products, and autobody

refinishing. The EPA has made no

decisions regarding further VOC

reductions beyond the reductions

specified as phase I in the OTAG

recommendations.7

Other more specific comments

concerning the OTAG recommendations

will be addressed throughout this

rulemaking as the issues are discussed.

F. Discussion of Comment Period and

Availability of Key Information

The EPA received numerous

comments concerning the adequacy of

the comment period for the November 7,

1997 NPR and May 11, 1998 SNPR.

Some commenters remarked that the

comment period for the NPR should be

extended to allow for development and

review of technical information,

including inventory data, growth

factors, and the resulting budget.

Commenters stated that the additional

time was particularly necessary for

subregional air quality modeling, which

is modeling designed to isolate the

impacts of emissions from a particular

State or group of States on downwind

areas. Many specifically requested an

additional 120 days, and one requested

an additional 9 months. Some

commenters indicated that EPA did not

incorporate their comments from the

NPR into the SNPR. Other commenters

insisted that key information supporting

the rule is not publicly available. The

EPA also received comments that

additional public hearings should be

held in other locations of the OTAG

region.

1. Request for Extension of the

Comment Period

The EPA allowed a 120-day public

comment period for the November 7,

1997 NPR, which closed on March 9,

1998. By notice (63 FR 17349, April 9,

1998), EPA reopened the comment

period for members of the public to

submit additional modeling analyses, as

well as comments concerning the

implications that any additional

modeling may have for the State NOx

budgets under consideration in the

November 7, 1997 proposal. The

comment period was reopened through

the end of the comment period on the

SNPR. The SNPR, which was published

on May 11, 1998, allowed a comment

period until June 25, 1998. Thus, for

most issues addressed in the NPR,

including air quality modeling issues,

commenters received an almost 8-month

formal comment period. Indeed, many

commenters had access to the NPR

immediately after October 10, 1997,

when it was signed and posted on an

EPA website. The Agency also received

a number of comments after June 25,

1998, which were also reviewed and

considered in developing the final rule.

The EPA believes this additional

opportunity for the public to submit

comments was reasonable. After March

9, 1998—the initial date for close of the

comment period on the NPR—EPA

received numerous comments on

various issues raised in the NPR,

including air quality issues. Many of

these comments were extensive, which

indicates that commenters received

adequate time.

With respect to the concern that EPA

did not incorporate comments received

on the NPR into the SNPR, it would not

have been practical for EPA to

incorporate comments received on the

NPR into the SNPR because the SNPR

was completed soon after the close of

the comment period for the NPR. In

general, the SNPR addressed different

aspects of the rule than the NPR, and

one of the purposes of the SNPR was to

take comment on several new issues, as

noted above. The EPA has addressed

comments on both the NPR and SNPR

in today’s action.

The major issues raised in the

comments are responded to throughout

the preamble of this final rule. A

comprehensive summary of all

significant comments, along with EPA’s

response to the comments which have

not been responded to in the preamble

(Response to Comments), can be found

in the docket for this rulemaking

(Docket No. A–96–56).
57364 Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations

8 Variable-Grid Urban Airshed Model.

9 In the NPR (62 FR 60318, 60363), EPA provided

estimates of the number of counties expected to

attain as a result of the NOX SIP call. The EPA will

update this list in the coming months. The updated

estimates of which counties will attain will be

based on more current air quality data and on the

State-by-State emissions budgets contained in

today’s final rule.

10The ‘‘transitional classification’’ EPA intends

for 8-hour ozone nonattainment areas is further

discussed in the NPR (62 FR 60318, 60363).

2. Request for Time to Conduct

Additional Modeling

The OTAG Policy Group, at its June

3, 1997 meeting, recommended that

States have the opportunity to conduct

additional local and subregional

modeling and air quality analyses, as

well as to develop and propose

appropriate levels and timing of

controls. The EPA received numerous

comments related to OTAG’s

recommendation. The commenters

requested that the Agency give States

more time to conduct this additional

modeling so that EPA could more

accurately assess each State’s

contribution to downwind

nonattainment.

The EPA signed the NPR on October

10, 1997, and posted it on a website at

that time, although it was not published

in the Federal Register until November

7, 1997. As noted above, EPA reopened

the comment period through June 25,

1998 for submittal of additional air

quality modeling runs. In effect, this has

extended the amount of time for

modeling analyses to over a year from

the date OTAG submitted its

recommendations, and to over 8 months

from the signature date for the NPR. By

the close of the comment period on June

25, 1998, EPA had received numerous

comments containing new and

extensive air quality modeling studies.

Accordingly, EPA believes that

commenters received adequate time.

3. Availability of Key Information

A number of commenters asserted

that EPA failed to make publicly

available key information, such as

modeling and emissions inventory data.

Specifically, commenters stated that

they did not have access to the

emissions data on which EPA based the

air quality modeling for the NPR. In

addition, according to some

commenters, several models used by

EPA and OTAG are proprietary models

and have not been generally available to

the public.

In Section III.A.2, Availability, the

Agency discusses the availability of

emissions inventory data to the public.

The OTAG and EPA conducted air

quality modeling runs to determine the

level of contribution from emissions in

upwind areas to ozone nonattainment in

downwind areas. Some of this modeling

employed UAM–V.8 The UAM–V has

generally been available to the public

for the purpose of analyzing information

relevant to today’s rulemaking. State

and local agencies, as well as utility

companies and other stakeholders, have

had access to licenses to use UAM–V.

Commenters objected that they were

obliged either to purchase licenses for

use of the UAM–V model or to employ

as a contractor the model owner, and

that these financial constraints

restricted their access to the model.

Because this model has, in general, been

privately developed, EPA believes that

reasonable fees for its use should be

expected. The EPA did not receive

information indicating that the

associated expenses were other than

reasonable. To the extent that

commenters experienced delays in

obtaining the UAM–V model, EPA

believes that the extensions of the

comment period resulted in adequate

time for comment. In any event, any

commenter who was not able to gain

access in the timeframe desired was able

to use a comparable model, such as the

Comprehensive Air Quality Model with

Extensions (CAMx), which is not

proprietary. For the purpose of

responding to public comments, EPA is

considering all information based on

CAMx and similar models.

The Agency made available additional

modeling runs used to determine

emissions changes, costs and cost

effectiveness for electricity generating

units (EGUs). These runs were placed

on the IPM Analyses web site at

www.epa.gov/capi, with links to EPA’s

Office of Air and Radiation Policy and

Guidance web site.

On August 10, the EPA placed in the

docket and made available on the web

site, modeling analyses and other

information supporting today’s action.

As noted above, by notice dated August

24, 1998 (63 FR 45032), EPA published

a notice of availability which stated that

throughout the course of the

rulemaking, EPA had placed

information in the docket or made it

available on various web sites. This

information included inventory data

and additional modeling runs. By

placing those materials in the docket

and informing the public of their

availability, EPA provided 4–6 weeks

for review and comment by the public.

The EPA did receive comments

concerning this information from the

Utility Air Regulatory Group on

September 9, and EPA is responding to

those comments in the Response To

Comments document. The EPA notes

that the additional modeling analyses

were performed in response to

comments received on the NPR urging

EPA to conduct State-by-State modeling.

The Agency does not believe it is

required to provide for additional

comment on every action it takes in

response to comment, particularly

where, as here, the new information

confirms the Agency’s proposed

conclusions. Therefore, the Agency did

not further extend the comment period.

4. Public Hearings

The Agency conducted two hearings

in Washington, DC, including a 2-day

hearing on February 3–4, 1998 for the

NPR, and a 1-day hearing on May 29,

1998 for the SNPR. Some commenters

believe that additional public hearings

should have been held in other

locations in the OTAG region. The EPA

believes these hearings provided

reasonable opportunity for oral

comment on the proposed rulemaking

given the timeframes associated with

this rulemaking. Therefore, the Agency

did not schedule any additional

hearings. The public also had an

opportunity to submit written testimony

within approximately 30 days after each

hearing date.

G. Implementation of Revised Air

Quality Standards

On July 18, 1997, EPA published its

final rule for strengthening the NAAQS

for ozone by establishing an 8-hour

standard (62 FR 38856). Current

monitoring data indicate that many

areas in the East, Midwest and South

violate the 8-hour NAAQS. Along with

areas violating the 1-hour NAAQS, areas

violating the 8-hour NAAQS are also

affected by the transport of ozone across

the East. The regional NOX reduction

strategy finalized in today’s action will

provide a mechanism to achieve

reductions that will assist States in

attaining and maintaining this revised

standard. In fact, the regional reductions

alone should be enough to enable the

vast majority of the new counties

violating the 8-hour NAAQS that are

located in States throughout the East to

attain the revised 8-hour standard.9

On July 16, 1997, President Clinton

issued a directive on the

implementation of the revised air

quality standards. This implementation

policy was described in the NPR (62 FR

60318, 60362–64). The EPA received

numerous comments on this

implementation policy and on EPA’s

plan to create a transitional

classification10 for 8-hour ozone

nonattainment areas that meet certain
Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations 57365

11For a complete listing of the guidance and other

actions EPA plans to issue to implement the revised

ozone and PM NAAQS, see a table on EPA’s

implementation website: http://

ttnwww.rtpnc.epa.gov/implement/actions.htm.

criteria. Since these comments concern

implementation efforts for the revised 8-

hour ozone standard and do not relate

directly to the NOX SIP call on which

EPA is taking final action in this

rulemaking, EPA is not responding in

detail to the comments. The EPA will

address implementation of the revised

standard separately. In August 1998,

EPA issued proposed guidance for

public comment to explain the

implementation policy in further detail

and to provide details on SIP

requirements for transitional areas (63

FR 45060, August 24, 1998). The EPA

expects to finalize the August 1998 draft

guidance, as well as guidance for areas

other than transitional, by December

1998.11

H. Summary of Major Changes Between

Proposals and Final Rule

This summary describes the major

changes that have occurred since the

NPR and SNPR in each of the following

sections of today’s final rule.

1. EPA’s Analytical Approach (Section

II.A)

• The NPR proposed two

interpretations for the section

110(a)(2)(D)(i)(I) provisions concerning

the ‘‘significant contribution’’ test.

Under the first, EPA would examine

certain factors relating to level of

emissions and their ambient impact to

determine whether to make a finding

that all of the emissions from a

particular State’s sources contribute

significantly to nonattainment or

maintenance problems downwind. If

EPA made such a finding, then EPA

would examine certain cost factors to

determine the extent to which the SIP

for the State must mitigate (reduce) its

emissions. Under the second

interpretation, EPA would examine all

of those factors together—level of

emissions, ambient impact, and costs—

to determine whether to make the

finding with respect to a specified

amount of emissions. If EPA made the

finding, then it would require the SIP to

eliminate that amount. In today’s final

rule, EPA is adopting the second

interpretation. The EPA indicates,

however, that it would adopt the same

rule if it were instead implementing the

first interpretation.

2. Cost Effectiveness of Emissions

Reductions (Section II.D.)

• The methodology of determining

cost effectiveness has not changed. For

all sources, the inventory and as a

result, the source-specific costs, in some

cases, have changed. This results in a

different overall budget level and a

different overall cost-effectiveness

value. For the non-EGUs, while the

methodology has not changed, the

analysis focuses on large non-EGU

sources. The methodology in the NPR

focused on all non-EGU sources.

3. Determination of Budgets (Section

III.)

• For EGU, the EPA maintained the

approach to use the higher, by State, of

1995 or 1996 heat input data to

calculate baseline heat input rates for

the NFR, and added 577 smaller units

to the State budget inventories which

had erroneously been omitted from the

NPR. These units included electricity

generating sources of 25 megawatts

(MW) or less of electrical output and

additional units not affected under the

Acid Rain Program. Additional controls

are not assumed for these sources, but

they are added to the budget at baseline

levels. The Agency has decided to use

State-specific growth factors derived

from application of the IPM using the

1998 Base Case and chose to retain the

0.15 lbs/mmBtu as the assumed uniform

control level for EGU budget emissions

determination.

• The EPA examined alternatives that

focus on non-EGU point source

reductions from the largest source

categories, and within each of these

categories assumed controls that would

result in a regionwide average cost

effectiveness less than $2000/ton. The

resulting budget assumes the emissions

reductions from large non-EGU sources

that are among the most cost effective to

control and does not include reductions

from smaller sources and sources that,

as a group, are not quite as cost effective

or efficient to control, or are already

covered by other Federal measures. As

a result, this final rule assumes, for

purposes of calculating the State NOX

budgets, the following emissions

decreases from uncontrolled levels for

the large (generally greater than 250

mmBtu or 1 ton/day non-EGU sources

(no emission reductions are assumed for

the smaller sources):

—Non-EGU boilers and turbines—60

percent decrease.

—Stationary internal combustion

engines—90 percent decrease.

—Cement manufacturing plants—30

percent decrease.

It should be noted that point sources

with capacities less than 250 mmBtu/hr

but with emissions greater than 1 ton/

day are not treated differently from

sources with capacities greater than 250

mmBtu/hr for purposes of calculating

the budget. This is a change from the

NPR which included RACT controls on

units with capacities less than 250

mmBtu/hr and emissions greater than 1

ton/day (see Section III.G.2.a). As under

the proposal, the rule allows States to

choose control measures other than the

EPA-assumed controls to meet the

numerical budgets.

• The EPA has implemented the

following changes that the Agency

proposed in the NPR for calculating

baseline NOX emissions from highway

vehicles. A 1995 baseline is used for the

final rule in place of the 1990 baseline

used in the NPR. The Highway

Performance and Monitoring System

data were used to estimate States’ 1995

vehicle miles traveled (VMT) by vehicle

category, except in those cases where

EPA accepted revisions offered in the

comments. Today’s action includes

those mobile source reductions which

EPA has determined are appropriate to

implement on a national basis, and

which have been promulgated in final

form or are expected to be promulgated

in final form before States are required

to comply with their budgets. The

highway vehicle budget components

include the emission reductions

resulting from implementation of the

National Low Emitting Vehicle (NLEV)

program, including the phase-in

schedule agreed to by the States,

automobile manufacturers, and EPA.

The highway budget components do not

include the effect of Tier 2 light-duty

vehicle and truck standards and any

associated fuel standards since these

standards have not yet been proposed.

The extent of the reformulated gasoline

(RFG) and inspection and maintenance

(I/M) programs was not assumed to

change beyond that assumed for the

NPR, except for those States that were

able to demonstrate that the NPR’s

modeling assumptions did not conform

to the State’s SIP and did not reflect

CAA requirements.

• The EPA has chosen to retain the

1990 baseline inventories for nonroad

mobile sources presented in the NPR for

today’s action, with additional changes

made in response to public comments.

The control strategies assumed for

calculating the nonroad and stationary

area source budget components have not

changed from the SNPR.

4. NOX Control Implementation and

Budget Achievement Dates (Section V)

• The EPA proposed that the SIP

revisions require full implementation of

the necessary State measures by

September 2002 and took comment on

a range of dates from September 2002

through September 2004. Based on
57366 Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations

public comments and feasibility

analyses conducted by EPA, the Agency

is requiring an implementation date of

May 1, 2003. The Agency is also

providing some compliance flexibility

to States for the 2003 and 2004 ozone

seasons by establishing State

compliance supplement pools. This is

described in Section III.F.6.

5. SIP Criteria (Section VI.A)

• The Agency has determined that the

additional SIP approvability criteria, as

proposed in the SNPR, should apply not

only when States choose to regulate

EGUs (63 FR 25912), but also when

States choose to regulate large steamproducing units (i.e., combustion

turbines and combined cycle systems

with a capacity greater than 250

mmBtu/hr).

• The Agency proposed revisions to

part 51 requiring continuous emissions

monitoring systems (CEMS) on all large

electrical generating and steamproducing sources which States elect to

subject to emissions reduction

requirements in response to this

rulemaking. The EPA took comment on

requiring that, if a State chooses to

regulate these sources to meet the SIP

call, the SIP must require these sources

to use the NOX mass monitoring

provisions of part 75, subpart H, to

demonstrate compliance with

applicable emissions control

requirements. After considering

comments, the Agency is requiring that,

in these circumstances, the SIP specify

that large sources comply with the

monitoring provisions of part 75,

subpart H, which includes non-CEMS

monitoring options for units that are

infrequently operated or units that have

low mass emissions.

6. Emissions Reporting Requirements

for States (Section VI.B)

• The proposed rule required that

States report full-year, as well as ozoneseason, emissions from all sources for

the triennial inventories commencing

with year 2002 emissions and the 2007

inventory, and for those sources for

which reports had to be submitted

annually starting with year 2003

emissions. The final rule requires only

ozone-season emissions reporting for all

sources.

• In the SNPR, the EPA proposed, for

purposes of reporting requirements, to

define a point source as a non-mobile

source which has NOX emissions of 100

tons/year or greater. Under today’s

action, States have the option of

establishing a smaller emission

threshold than 100 tons/year of NOX

emissions in defining point source. This

will allow the definition of point source

to remain consistent with current

definitions in local areas.

7. NOX Budget Trading Program

(Section VII.)

• For States that choose to participate

in the NOX Budget Trading Program, the

preamble clarifies the intent of the

model rule and identifies areas of the

rule where States have flexibility to

include variations in their State rules.

• In the SNPR, the Agency solicited

comment on a range of options for

incorporating banking into the trading

program. After considering these

comments, the Agency is including

banking provisions in the final rule. The

provisions allow for unlimited banking

starting in 2003 and includes a flow

control mechanism to limit the

emissions variability associated with

banking.

• One of the banking approaches

presented in the SNPR included the

option for sources to generate and use

early reduction credits. Consistent with

the provisions of the NOX SIP call

which provide for State compliance

supplement pools, the final rule allows

States to issue early reduction credits

for certain NOX emissions reductions

achieved between September 30, 1999

and May 1, 2003.

• The final rule clarifies the timing

requirements for State submission of

allowance allocations to EPA and, as

proposed, lays out an allocation

approach. Each State remains free to

adopt the final rule’s allocation

approach or adopt an allocation scheme

of its own, provided it meets the

specified timing requirements, requires

new sources to hold allowances, and

does not allocate more allowances than

are available in the State trading budget.

8. Interaction with Title IV NOX Rule

(Section VIII.)

• In the SNPR, EPA proposed

revisions to part 76 addressing the

interaction between title IV and the NOX

SIP call. In this final rule, EPA explains

that the Agency is not adopting any of

the proposed revisions to part 76.

9. Administrative Requirements

(Section X.)

• NPR Section VIII, Regulatory

Analyses, has been replaced in the final

rule by Section X.A, Executive Order

12866: Regulatory Impacts Analysis.

The new final rule Section X.A

indicates that EPA has prepared a RIA

for the final rule and cites the cost and

benefit estimates from that analysis.

• The final rule adds several Sections

under X, Administrative Requirements,

that were absent from the NPR. These

include: Paperwork Reduction Act;

Executive Order 13045: Protection of

Children from Environmental Health

Risks and Safety Risks; Executive Order

12898: Environmental Justice; Executive

Order 12875: Enhancing the

Intergovernmental Partnerships;

Executive Order 13084: Consultation

and Coordination with Indian Tribal

Governments; Judicial Review; and

Congressional Review Act. These new

Sections provide a more comprehensive

summary of the Acts and Executive

Orders that could apply to the final rule.

Each Section identifies the requirements

of the relevant Act or Executive Order,

indicates EPA’s interpretation of

whether the Act or Executive Order

actually applies to this rulemaking, and,

if so, indicates how the Agency has

addressed the Act or Executive Order.

II. EPA’s Analytical Approach

A. Interpretation of the CAA’s Transport

Provisions

As indicated in the NPR, 62 FR 60323,

the primary statutory basis for today’s

action is the ‘‘good neighbor’’ provision

of section 110(a)(2)(D)(i)(I), under

which, in general, each SIP is required

to include provisions assuring that

sources within the State do not emit

pollutants in amounts that significantly

contribute to nonattainment or

maintenance problems downwind. This

statutory requirement applies to SIPs

under both the 1-hour ozone NAAQS

and the 8-hour ozone NAAQS.

1. Authority and Process for Requiring

SIP Submissions Under the 1-Hour

Ozone NAAQS

a. Authority for Requiring SIP

Submissions under the 1-Hour NAAQS.

Each State is currently required to have

in place a SIP that implements the 1-

hour ozone NAAQS for areas to which

that standard still applies. In the

NAAQS rulemaking, EPA determined

that the 1-hour NAAQS would cease to

apply to areas that EPA determines have

air quality in attainment of that NAAQS

(40 CFR 50.9(b)). In two recent

rulemakings, EPA identified numerous

areas of the country to which the 1-hour

NAAQS no longer applies. ‘‘Final Rule:

Identification of Ozone Areas Attaining

the 1-Hour Standard and to Which the

1-Hour Standard is No Longer

Applicable,’’ (63 FR 31014, June 5,

1998); ‘‘Final Rule: Identification of

Additional Ozone Areas Attaining the 1-

Hour Standard and to Which the 1-Hour

Standard is No Longer Applicable,’’ (63

FR 27247, July 22, 1998).

The 1-hour NAAQS remains

applicable to areas whose air quality

continues to monitor nonattainment. As

noted above in Section I.B, General
Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations 57367

12As discussed in the NPR and in greater detail

further below, the basis for requiring a transportrelated SIP revision for the 8-hour standard is the

requirement in section 110(a)(1) that States submit

SIPs meeting the requirements of section 110(a)(2)

within 3 years (or an earlier date established by

EPA) of promulgation of a new or revised NAAQS.

This is discussed in further detail below.

13Taken to its logical conclusion, the

commenters’ argument would mean that States are

precluded from submitting a section 110(a)(2)(D)

SIP unless it reflects measures recommended

through the transport commission process. The EPA

does not believe that Congress would first establish

a specific mandate (to submit a SIP to address

interstate transport) and then limit it in such a

cryptic fashion. If Congress intended section

110(a)(2)(D) SIPs to only reflect transport

commission recommendations, Congress could

have specifically referenced sections 176A and 184

in section 110(a)(2)(D), rather than generally

providing that SIPs be ‘‘consistent’’ with title I of

the CAA.

Factual Background, these include

many major urban areas in the eastern

half of the United States. States that

contain these areas remain responsible

for meeting CAA requirements

applicable to those areas for the purpose

of attaining the 1-hour NAAQS. For

example, States are responsible for

attainment demonstrations for areas

designated nonattainment and classified

as moderate or higher.

By the same token, States that are

upwind of these areas are responsible to

meet the ‘‘good neighbor’’ requirements

of section 110(a)(2)(D). This

responsibility is not alleviated simply

because, for areas other than the current

nonattainment areas, the 8-hour NAAQS

has replaced the 1-hour NAAQS.

b. Process for Requiring SIP

Submissions under the 1-Hour NAAQS.

As explained in the NPR, the

appropriate route for EPA to require SIP

submissions under section

110(a)(2)(D)(i)(I) with respect to the 1-

hour standard is issuance of a ‘‘SIP call’’

under section 110(k)(5).12 Section

110(k)(5) authorizes EPA to find that a

SIP is substantially inadequate to meet

a CAA requirement and to require (‘‘call

for’’) the State to submit, within a

specified period, a SIP revision to

correct the inadequacy. Specifically,

section 110(k)(5) provides, in relevant

part:

Whenever the Administrator finds that the

applicable implementation plan for any area

is substantially inadequate to attain or

maintain the relevant [NAAQS], to mitigate

adequately the interstate pollutant transport

described in section 176A or section 184, or

to otherwise comply with any requirement of

this Act, the Administrator shall require the

State to revise the plan as necessary to

correct such inadequacies. The Administrator

shall notify the State of the inadequacies, and

may establish reasonable deadlines (not to

exceed 18 months after the date of such

notice) for the submission of such plan

revisions.

By today’s action, EPA is determining

that the SIPs for the specified

jurisdictions are substantially

inadequate to comply with the

requirements of section 110(a)(2)(D)(i)(I)

because the relevant SIPs do not contain

adequate provisions prohibiting their

sources from emitting amounts of NOX

emissions that contribute significantly

to nonattainment in downwind areas

that remain subject to the 1-hour

NAAQS. Based on these determinations,

EPA is requiring the identified States to

submit SIP revisions containing

adequate provisions to limit emissions

to the appropriate amount.

If a State does not submit the required

SIP provisions in response to this SIP

call, EPA will issue a finding that the

State failed to make a required SIP

submittal under section 179(a). This

finding has implications for sanctions as

well as for EPA’s promulgation of

Federal implementation plans (FIPs).

Sanctions and FIPs are discussed in

Section VI, SIP Criteria and Emissions

Reporting Requirements.

(1) Commenters’ Arguments

Concerning the Transport Provisions.

Commenters argued that EPA does not

have unilateral authority to issue a SIP

call under section 110(k)(5) to require

States to remedy SIPs that do not meet

the requirements of section 110(a)(2)(D).

The commenters noted that when

Congress amended the CAA in 1990,

Congress provided that the sole

authority for EPA and States to address

interstate transport of pollution is

through transport commissions. In

support, the commenters state that

Congress: (i) Added sections 176A and

184, which authorize the establishment

of transport regions and the formation of

transport commissions; (ii) revised

section 110(k)(5) to refer to those

transport provisions; and (iii) revised

section 110(a)(2)(D)(i) to require that SIP

provisions designed to eliminate

interstate pollutant transport be

consistent with other CAA

requirements. According to the

commenters, these provisions, read as a

whole, mandate that if EPA believes that

a transport problem exists, EPA’s sole

recourse is to form a transport region

under sections 176A and/or 184; EPA

may issue a SIP call to mandate

compliance with section 110(a)(2)(D)(i)

only in response to a recommendation

of the transport region. The commenters

also claim that this scheme is sensible

because it provides a consensual forum

for States to address interstate pollution

rather than allowing unilateral action on

the part of EPA or a State.

The EPA disagrees with the

commenters’ conclusion that these

statutory provisions make clear that

EPA cannot require a State to address

interstate transport without first

establishing a transport commission and

in the absence of a recommendation

from the transport commission. There is

no language of limitation in sections

110(a)(2)(D) or (k)(5), or 176A, or 184.

Nor is there any support in the

legislative history for such a narrow

reading of the statute. Moreover, under

the commenters’ interpretation, the

CAA Amendments of 1990 have placed

greater constraints on States’ and EPA’s

ability to address the interstate transport

of pollution. Such an interpretation

would be inconsistent with the overall

purpose of the CAA to ensure healthful

air. Thus, EPA believes that the

transport provisions were added as an

additional tool to address interstate

transport but were not intended to

preclude other methods of addressing

interstate pollution than prior to passage

of the amendments.

Under the 1990 Amendments,

Congress recognized the growing

evidence that ozone and its precursors

can be transported over long distances

and that the control of transported

ozone was a key to achieving attainment

of the ozone standard across the nation

(Cong. Rec. S16903 (daily ed. Oct. 27,

1990) (statement of Sen. Mitchell);

S16970 (conference report) S16986–87

(statement of Sen. Lieberman)). Thus, in

1990, Congress added a new mechanism

to address interstate transport.

Specifically, Congress enacted sections

176A and 184, which provide a

mechanism for States to work together

to address the interstate transport

problem. However, by their terms, these

sections simply provide authority for

EPA to designate transport regions and

establish transport commissions. There

is nothing in the language of these

provisions that indicates that they

supersede the other statutory

mechanisms for addressing interstate

transport, or that they now provide the

sole mechanism for resolving interstate

pollution transport.

Moreover, although Congress

expressly added these two provisions

through the 1990 Amendments,

Congress did not in any way limit

section 110(a)(2)(D), which requires

States to address interstate transport in

their SIPs. The addition of the language

providing that States’ actions under

section 110(a)(2)(D) be ‘‘consistent with

[title I] of the Act’’ cannot be read to

limit the controls States may adopt to

meet section 110(a)(2)(D) to those

recommended by a transport

commission.13 After all, the transport

region provisions are only two of many

provisions in title I. Rather, this
57368 Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations

14 In Commonwealth of Virginia v. EPA, 108 F.3d

1397 (D.C. Cir. 1997), the court vacated EPA’s SIP

call in response to the Northeast Ozone Transport

Commission’s recommendation on the basis that the

EPA could not require States to adopt a specific

control measure under its section 110(k)(5)

authority and that, in any event, EPA could not

require States to adopt stricter motor vehicle

emission standards under either section 110(k)(5) or

section 184.

language concerning consistency should

be read as clarifying that any section

110(a)(2)(D) requirement must be

consistent with other provisions of title

I. Similarly, this language makes

explicit that SIP revisions required in

accordance with the procedures of the

transport provisions would meet the

requirements of section 110(a)(2)(D)(i).

Furthermore, it is significant that

Congress did not in any sense bind

EPA’s ultimate discretion to determine

whether State plans appropriately

address interstate transport. Under

sections 176A and 184, the States may

only make recommendations to EPA.

Thus, under the transport provisions, as

well as the general SIP requirements of

section 110(a)(2), EPA must ultimately

decide whether the SIP meets the

applicable requirements of the CAA. If,

as the commenters contend, EPA is

limited to calling on States to address

interstate transport only by strategies

recommended by the State, then EPA

would be precluded from ensuring that

States address interstate transport. For

example, EPA could establish a

transport commission but the

commission could fail to make

recommendations or make insufficient

recommendations. (Section 176A

provides that transport commissions

may make recommendations to EPA

only by ‘‘majority vote of all members’’

other than those representing EPA.)

Such a reading of the statute would be

absurd in light of the growing

recognition at the time of the 1990

Amendments that transport is a real

threat to the primary purpose of title I

of the CAA—attainment of the NAAQS.

By the same token, in amending

section 110(k)(5) in the 1990

Amendments, Congress did not add

anything that explicitly provides that, in

the case of interstate transport, section

110(k)(5) would apply only when EPA

approved (or substituted measures for) a

transport commission’s

recommendations. The reference in

section 110(k)(5) to the transport

provisions of sections 176A and 184

does not preclude EPA’s use of the SIP

call provision to call on States to ensure

their SIPs meet the requirements of

section 110(a)(2)(D)(i). Section 110(k)(5)

also provides for EPA to call on States

‘‘to otherwise comply with requirements

of this Act;’’ among the requirements in

chapter I of the CAA is the requirement

in section 110(a)(2)(D). The reference in

section 110(k)(5) to the transport

provisions simply makes explicit that

EPA may employ section 110(k)(5) for

the additional purpose of requiring SIPs

to include the control measures as

recommended by transport commissions

and approved by EPA under the

transport provisions.

Moreover, there is no indication in

the legislative history of the 1990

Amendments that Congress intended

the sections 176A and 184 transport

provisions to supersede the section

110(k)(5) SIP call mechanism for

ensuring compliance with section

110(a)(2)(D)(i). Reading the transport

provisions to supersede the SIP call

mechanism would constitute a

significant change from the CAA as it

read prior to the 1990 Amendments.

Even if the statute is ambiguous as to

whether the transport provisions

supersede the SIP call mechanism—and

EPA believes the statute is clear that the

transport provisions do not supersede—

congressional silence would suggest that

Congress did not intend such a

significant change (See generally

Harrison v. PPG Industries, Inc., 446

U.S. 578, 602, 100 S.Ct. 1889, 1902, 64

L.Ed.2d 525 (1980) (Rehnquist, J.,

dissenting), cited with approval in

Chisom v. Roemer, 501 U.S. 380, 396 n.

23, 111 S.Ct. 2354, 2364 n. 23, 115

L.Ed.2d 348 (1991)).

Finally, the commenter asserts that

EPA’s interpretation of the CAA to

allow a SIP call in the absence of a

transport commission recommendation

reads out of the CAA the consensual

transport commission procedures under

sections 176A and 184. This is simply

not true. The EPA interprets the

transport commission process to be one

tool to assess and address interstate

transport. In fact, the Northeast Ozone

Transport Commission, under section

184, has been active since enactment of

the 1990 Amendments. In 1995, EPA

approved a recommendation of that

commission (60 FR 4712 14). Transport

commissions remain a viable means for

dealing with interstate transport.

Furthermore, contrary to the general

implication of the commenter’s remark,

the OTAG process, though not a formal

transport commission, provided an

opportunity not only for Federal and

State governments to assess jointly the

transport issue, but also involved

industry, environmental groups and

others. The EPA based its SIP call on

information developed through OTAG,

as well as additional analyses performed

by the Agency and information

submitted by a variety of groups during

the comment period on the proposed

rule. Thus, the OTAG process contained

consensual elements.

(2) Commenters’ Arguments

Concerning the Virginia case. Under one

of the approaches described in the

proposed rule, EPA proposed to

determine, for each of various upwind

States, the aggregate ‘‘amounts’’ of air

pollutants (NOX) that contribute

significantly to nonattainment, and that,

therefore must be prohibited by the

various SIPs. The NOX emissions budget

for each State is an expression of the

amount of NOX emissions that would

remain after the State prohibits the

amount that contributes significantly to

downwind nonattainment. In the final

rule issued today, EPA has continued

this approach, establishing emissions

budgets for each of the 23 jurisdictions

based on required reductions. This

determination is an important step

toward assuring that overall air quality

standards are met downwind.

Commenters argue that even if EPA

has authority to call on States to address

interstate transport, EPA does not have

the authority under section 110(a)(2)(D)

to mandate that upwind States limit

NOX emissions to specified amounts.

Rather, according to this view, EPA’s

authority is limited to determining that

the upwind States’ SIPs are inadequate,

and generally requiring the upwind

States to submit SIP revisions to correct

the inadequacies. The upwind States

would then, according to this view,

submit a SIP revision that implements

what the upwind States determine to be

the appropriate amount of NOX

reductions. If EPA believes that those

amounts are too small to correct the

inadequacy, EPA could disapprove the

SIP revisions.

Proponents of this view rely on the

recent decision in Virginia v. EPA, 108

F.3d 1397, 1406–10 (D.C. Cir. 1997)

(Virginia) (citing Train v. NRDC), in

which the court vacated EPA’s SIP call

on the basis that through it, EPA gave

States no choice but to adopt the

California low emission vehicle (LEV)

program. The court found that the

language in section 110(k)(5) that

provides EPA with the authority to call

on a State to revise its SIP ‘‘as

necessary’’ to correct a substantial

inadequacy did not change the

longstanding precept that States have

the primary authority for determining

the mix of control measures needed to

attain the NAAQS.

The EPA disagrees that the CAA

prohibits EPA from establishing an

emissions budget through a SIP call

requiring upwind States to prohibit

emissions that contribute significantly

to downwind nonattainment. Section
Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations 57369

15The EPA is not contending that the ‘‘as

necessary’’ language in section 110(k)(5) provides

the basis for EPA’s authority to identify the

emissions budget for upwind States.

16The court’s decision in Train v. NRDC appears

to rely on the plain language of the statute in

holding that a State is primarily responsible for

determining the mix of control measures necessary

to demonstrate attainment within that State’s

borders. The court in Virginia appears to adopt this

‘‘plain meaning’’ interpretation without addressing

that the language in section 107(a) applies only to

intrastate issues. This issue is not relevant in the

present case, however, since States are free to

decide the mix of control measures under today’s

final action.

110(a)(2)(D) is silent regarding whether

States or EPA are to determine the level

of emission reductions necessary to

mitigate significant contribution. The

caselaw cited by the commenters only

provides that States are primarily

responsible for determining the mix of

control measures—not the aggregate

emission reduction levels that are

necessary. Moreover, Train v. NRDC,

which underlies the Virginia court’s

decision, relied on section 107(a) of the

CAA, which specifies only that each

State is primarily responsible for

determining a control strategy to attain

the NAAQS ‘‘within such State.’’

Section 110(a)(2)(D) does not provide

who—EPA or the States—is to

determine the level of emission

reductions necessary to address

interstate transport. As quoted above,

section 110(a)(2)(D)(i)(I) requires that

SIPs contain ‘‘adequate provisions

prohibiting * * * [sources] from

emitting any air pollutant in amounts

which will contribute significantly to

nonattainment’’ downwind. Nor does

this provision indicate the criteria for

determining the ‘‘amounts’’ of

pollutants that contribute significantly

to nonattainment downwind. Nor does

this provision indicate the process for

determining those ‘‘amounts,’’ including

whether EPA or the States should carry

out this responsibility. 15 Under Chevron

U.S.A., Inc. v. Natural Resources

Defense Council, 468 U.S. 1227, 105

S.Ct. 28, 82 L.Ed.2d 921 (1984)

(Chevron), because the statute does not

answer these specific issues, EPA has

discretion to provide a reasonable

interpretation.

Neither the decision in Virginia, nor

the body of caselaw upon which it

relies, addresses this issue. Rather, these

cases address solely the division

between the States and EPA regarding

the initial identification of control

measures necessary to attain the

ambient air quality standards. The issue

before the court in Virginia was whether

EPA had offered States a choice in

selecting control measures or instead

had mandated the adoption of a specific

control measure. Relying on Train v.

NRDC, 421 U.S. 60, 95 S.Ct. 1470, 43

L.Ed.2d 731 1975), the Virginia court

found that under title I of the CAA, EPA

is required to establish the overall air

quality standards, but the States are

primarily responsible for determining

the mix of control measures needed to

meet those standards and the sources

that must implement controls, as well as

the applicable level of control for those

sources. The EPA must then review the

State’s determination only to the extent

of assuring that the overall air quality

standards are met. If EPA determines

that the SIP’s mix of control measures

does not result in achieving the overall

air quality standards, EPA is required to

disapprove the SIP and promulgate a

FIP, under which EPA selects the

sources for emissions reductions

(Virginia, 108 F.3d at 1407–08, citing

Train v. NRDC, 421 U.S. 60, 95 S.Ct.

1470, 43 L.Ed.2d 731 (1975); Union

Electric Co. v. EPA, 427 U.S. 246, 96

S.Ct. 2518, 49 L.Ed.2d 474 (1976)). This

line of cases, which focuses on the

selection of controls, does not address

whether EPA or the States—in the first

instance—should determine the

aggregate amount of reductions

necessary to address interstate transport.

Moreover, NRDC v. Train addresses

State plans for purposes of intrastate

emissions planning. In determining that

States have the primary authority for

determining the control measures

needed to attain the standard, the court

relied on section 107(a) of the CAA,

which provided (and still provides) that:

Each State shall have the primary

responsibility for assuring air quality within

the entire geographic area comprising such

State by submitting an implementation plan

which will specify the manner in which

national primary and secondary ambient air

quality standards will be achieved and

maintained within each air quality region in

such State.’’

(421 U.S. at 64, 95 S.Ct at 1474–75

(emphasis added)).

Thus, the underlying support for the

court’s determination in Train v. NRDC

applies only where a State is

determining the mix of controls within

its boundaries, not to the broader task of

determining the aggregate emissions

reductions needed in conjunction with

emissions reductions from a number of

other States in order to address the

impact of transported pollution on

downwind States. 16

Although the cases to date have not

addressed directly whether it is the

province of EPA or the States to

determine the aggregate amounts of

emissions to be prohibited (and hence,

the amounts that may remain—i.e., the

emissions budgets), EPA believes it

reasonable to interpret the ambiguity in

section 110(a)(2)(D)(i)(I) to include this

determination among EPA’s

responsibilities, particularly in the

current circumstances. Determining the

overall level of air pollutants allowed to

be emitted in a State is comparable to

determining overall standards of air

quality, which the courts have

recognized as EPA’s responsibility, and

is distinguishable from determining the

particular mix of controls among

individual sources to attain those

standards, which the caselaw identifies

as a State responsibility. In Train, a

State was required to assure that its own

air quality attained overall air quality

standards and to implement emissions

controls to do so. Under these

circumstances, the court clarified that

while the responsibility for determining

the overall air quality standards was

EPA’s, the responsibility for

determining the specific mix of controls

designed to achieve that air quality was

the State’s. By comparison, as stated

earlier, a transport case, under section

110(a)(2)(D)(i), does not concern any

requirement of the upwind State to

assure that its own air quality attains

overall air quality standards. Rather, a

transport case concerns the upwind

State’s requirement to assure that its

emissions are reduced to a level that

will not contribute significantly to

nonattainment downwind. Determining

this overall level of reductions for the

upwind State is analogous to

determining overall air quality

standards, and, thus, should be the

responsibility of EPA.

Once EPA determines the overall

level of reductions (by assigning the

aggregate amounts of emissions that

must be eliminated to meet the

requirements of section 110(a)(2)(D)), it

falls to the State to determine the

appropriate mix of controls to achieve

those reductions. Unlike the regulation

at issue in Virginia, today’s regulation

establishing emission budgets for the

States does not limit the States to one

set of emission controls. Rather, the

States will have significant discretion to

choose the appropriate mix of controls

to meet the emissions budget. The EPA

has based the aggregate amounts to be

prohibited on the availability of a subset

of cost-effective controls that are among

the most cost effective available. As

explained elsewhere in this final rule

and the NPR, the State may choose from

a broader menu of cost-effective,

reasonable alternatives, including some

(e.g., vehicle inspection and

maintenance programs and reformulated
57370 Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations

gasoline) that may even be more

advantageous in light of local concerns.

The task of determining the

reductions necessary to meet section

110(a)(2)(D) involves allocating the use

of the downwind States’ air basin. This

area is a commons in the sense that the

contributing State or States have a

greater interest in protecting their local

interests than in protecting an area in a

downwind State over which they do not

have jurisdiction and for which they are

not politically accountable. Thus, in

general, it is reasonable to assume that

EPA may be in a better position to

determine the appropriate goal, or

budget, for the contributing States,

while leaving to the contributing States’

discretion to determine the mix of

controls to make the necessary

reductions.

The EPA’s decision to assign the

budgets in the final rule is particularly

reasonable. Today’s rulemaking

involves almost half the States in the

Nation, and although these States

participated in OTAG beginning more

than 3 years ago, they still have not

agreed on whether particular upwind

States should be treated as having

sources whose emissions contribute

significantly to downwind

nonattainment, what the aggregate level

of emissions reductions should be, or

what the State-by-State reductions

should be. The sharply divergent

positions taken by the States in their

comments on the NPR and SNPR raise

doubts that those disagreements could

ever be resolved by consensus. It is most

efficient—indeed necessary—for the

Federal government to establish the

overall emissions levels for the various

States. This is particularly true for an

interstate pollution problem such as the

one being dealt with in this action

where the downwind areas at issue are

affected by pollution coming from

several States and the actions taken by

each of the concerned States could have

an effect on the appropriate action to be

taken by another State. For example, if

EPA did not specify the emissions to be

prohibited from each of the various

States affecting New York City, each of

those States might claim it could reduce

its emissions less provided other States

did more. Or, a State close to New York

might assert that it could just as

effectively deal with its contribution to

New York through additional VOC,

rather than NOX, reductions and submit

a section 110(a)(2)(D) SIP based on a

VOC-control rather than NOX-control

strategy. These choices, however, even

assuming they were valid, necessarily

relate to the choices that would need to

be made by the other upwind States

(e.g., Pennsylvania’s choice of a VOCdominated 110(a)(2)(D) control strategy

to deal with its contribution to New

York could affect what Ohio or New

Jersey would need to do to deal with

their own contributions by lowering the

overall level of NOX reductions being

obtained throughout the pertinent

region). Where many States are involved

and the choices of each individual State

could affect the choices and decisions of

the other States the need for initial

federal action is manifest. The EPA’s

action to determine the amount of NOX

emissions that each of the States must

prohibit in this widespread geographic

area is needed to enable the States to

decide expeditiously how to achieve

those reductions in an efficient manner

that will not undermine the actions of

another State. By notifying each State in

advance of its reduction requirements,

EPA enables each State to develop its

plan with full knowledge of the amount

and kind of reductions that must be

achieved both by itself and other

affected States. The EPA’s action

provides the minimum framework

necessary for a multi-state solution to a

multi-state problem while preserving

the maximum amount of state flexibility

in terms of the specific control measures

to be adopted to achieve the needed

emission reductions. The

reasonableness of EPA’s approach to the

interstate ozone transport problem was

recently recognized by a US Court of

Appeals in the context of upholding

EPA’s redesignation of the Cleveland

ozone nonattainment area to attainment

in light of EPA’s approach to the

regional transport problem. In the

course of doing so the court rejected the

contention that a separate analysis of

the current adequacy of the Cleveland

SIP under section 110(a)(2)(D) was

required as a prerequisite to

redesignation. The court, after

describing the November 7, 1997

proposed SIP call and the path EPA was

on to deal with this multi-state regional

problem, upheld EPA’s redesignation

and stated that ‘‘[w]e find that the EPA’s

approach to the regional transport

problem is reasonable and not arbitrary

or capricious.’’ Southwestern

Pennsylvania Growth Alliance v.

Browner, 144 F.3d 984, 990 (6th Cir.

1998).

As noted above, commenters have

argued that if EPA determines to issue

any SIP call, the SIP call must be more

general (i.e., one that simply requires

revised SIPs from upwind areas) and not

specify the amounts of NOX emissions

that those areas must prohibit. However,

if EPA issued a general SIP call and an

upwind State responded by submitting

an inadequate SIP revision, EPA would

disapprove that SIP, and in the

disapproval rulemaking, EPA would be

obliged to justify why the submitted SIP

was unacceptable. Without determining

an acceptable level of NOX reductions,

the upwind State would not have

guidance as to what is an acceptable

submission. The EPA’s determination,

as part of the issuance of the SIP call,

of the amounts of NOX emissions the

SIPs must prohibit obviously provides

for more efficient and smooth-running

administrative processes at both the

State and Federal levels. For the same

reasons that EPA believes it is

appropriate for the Agency to establish

the emissions budgets under the

authority of section 110(a)(2)(D) and

(k)(5), EPA believes that it is necessary

to do so through a rule under the

general rulemaking authority of section

301(a). Setting such a rule is necessary,

as a practical matter, for the

Administrator’s effective

implementation of section 110(a)(2)(D).

See NRDC v. EPA, 22 F.3d 1125, 1146–

48. Without such a rule the States could

be expected to submit SIPs reflecting

their conflicting interests, which could

result in up to 23 separate SIP

disapproval rulemakings in which EPA

would need to define the requirements

that each of those States would need to

meet in their later, corrective SIPs. That

in turn would trigger a new round of SIP

rulemakings to judge those corrective

SIPs. The delay attendant to that process

would thwart timely attainment of the

ozone standards.

2. Authority and Process for Requiring

SIP Submissions under the 8-Hour

Ozone NAAQS

a. Authority for Requiring SIP

Submissions under the 8-Hour NAAQS.

(1) SIP Submissions Under CAA Section

110(a)(1). In the NPR and SNPR, EPA

proposed to require the 23 upwind

jurisdictions to submit SIP revisions to

reduce emissions that exacerbate ozone

problems in downwind States under the

8-hour ozone NAAQS, as well as the 1-

hour NAAQS. The EPA recognized that

under the 8-hour NAAQS, areas have

not yet been designated as attainment,

nonattainment, or unclassifiable, and

are not yet required to have SIPs in

place. Even so, EPA proposed that

upwind areas be required to submit SIPs

meeting the requirements of section

110(a)(2)(D)(i)(I) with respect to the 8-

hour NAAQS.

In today’s action, EPA is confirming

its view that it has authority under the

8-hour NAAQS to require SIP submittals

under section 110(a)(2)(D)(i)(I) to reduce

NOX emissions by the prescribed

amounts. Section 110(a)(1) provides, in

relevant part—
Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations 57371

17As quoted above, section 172(b) refers to

‘‘applicable requirements of * * * section

110(a)(2).’’ This reference appears to mean those

requirements of section 110(a)(2) that either (i)

relate to all SIP submissions, such as the

requirement for reasonable notice and public

hearing in the language at the beginning of section

110(a)(2); or (ii) relate particularly to SIP

submissions required for nonattainment areas, but

that have not yet been submitted by the State.

18Section 110(a)(2)(D)(i)(I) further provides that a

SIP must prohibit emissions that ‘‘interfere with

maintenance by * * * any other State.’’

Each State shall * * * adopt and submit to

the Administrator, within 3 years (or such

shorter period as the Administrator may

prescribe) after the promulgation of a

national primary ambient air quality standard

(or any revision thereof) * * * a plan which

provides for implementation, maintenance,

and enforcement of such primary standard in

each (area) within such State.

Section 110(a)(2) provides, in relevant

part—

Each implementation plan submitted by a

State under this Act shall be adopted by the

State after reasonable notice and public

hearing. Each such plan shall [meet certain

requirements, including those found in

section 110(a)(2)(D)].

The provisions of section 110(a)(1)

and (a)(2) apply by their terms to all

areas, regardless of whether they have

been designated as attainment,

nonattainment, or unclassifiable under

section 107. The plain meaning of these

provisions, read together, is that SIP

revisions are required under the revised

NAAQS within 3 years of the date of

revision, or earlier if EPA so requires,

and that those SIP revisions must meet

the requirements of section 110(a)(2),

including subparagraph (D).

That the SIP submission requirements

of section 110(a)(1) are triggered by the

promulgation of a new or revised

NAAQS is made even clearer by

comparing section 172(b), which applies

by its terms only to areas that have been

designated nonattainment under section

107. Section 172(b) provides, in relevant

part—

At the time the Administrator promulgates

the designation of any area as nonattainment

with respect to a [NAAQS] under section

107(d) * * *, the Administrator shall

establish a schedule according to which the

State containing such area shall submit a

plan or plan revision * * * meeting the

applicable requirements of subsection (c) of

this section and section 110(a)(2) * * * Such

schedule shall at a minimum, include a date

or dates, extending no later than 3 years from

the date of the nonattainment designation, for

the submission of a plan or plan revision

* * * meeting the applicable requirements of

subsection (c) of this section and section

110(a)(2) * * *

Section 172(b) establishes the

schedule for submissions due with

respect to nonattainment areas under

sections 172(c) and 110(a)(2). The

section 172(c) requirements apply only

with respect to areas designated

nonattainment.17

In the NPR, EPA proposed that

section 110(a)(1) mandates SIP

submissions meeting the requirements

of section 110(a)(2)(D) and provides full

authority for EPA to establish a

submission date within 3 years of the

July 18, 1997 8-hour ozone NAAQS

promulgation date (62 FR 38856

(NAAQS rulemaking): 62 FR 60325

(NOx SIP call NPR)). The EPA further

asserted in the NPR that EPA has the

authority to establish different submittal

schedules for different parts of the

section 110(a)(1) SIP revision, and that

EPA may require the section

110(a)(2)(D) submittal first so that

upwind reductions may be secured at an

earlier stage in the regional SIP planning

process (62 FR 60325). Subsections (ii)

and (iii) of this section further

elaborates on the reasoning underlying

EPA’s decision to retain its proposal to

require SIP submissions under section

110(a)(2)(D) for the 8-hour standard.

(2) Commenters and the Definition of

‘‘Nonattainment.’’ Commenters

challenged several aspects of EPA’s

proposal to evaluate the contribution of

upwind areas under the 8-hour NAAQS.

Commenters asserted that section

110(a)(2)(D)(i) applies to constrain

emissions from upwind sources only

with respect to downwind areas that are

designated nonattainment. According to

these commenters, until EPA designates

areas nonattainment under the 8-hour

NAAQS, EPA has no authority to

require SIP submissions, under section

110(a)(1), from upwind areas with

respect to the 8-hour NAAQS. One

commenter pointed out that the new

source review requirements and ozone

nonattainment requirements enacted in

the 1990 Amendments apply only to

areas designated nonattainment.

The EPA disagrees with this

comment. Section 110(a)(2)(D)(i)(I)

provides that a SIP must prohibit

emissions that ‘‘contribute significantly

to nonattainment in * * * any other

State.’’ 18 The provision does not, by its

terms, indicate that this downwind

‘‘nonattainment’’ must already have

been designated under section 107 as a

nonattainment ‘‘area.’’ If the provision

were to employ the term ‘‘area’’ in

conjunction with the term

‘‘nonattainment,’’ then it would have to

be interpreted to apply only to areas

designated nonattainment. Other

provisions of the CAA do employ the

term ‘‘area’’ in conjunction with

‘‘nonattainment,’’ and these provisions

clearly refer to areas designated

nonattainment (e.g., sections

107(d)(1)(A)(i), 181(b)(2)(A),

211(k)(10)(D)). Similarly, the provisions

to which the commenter appeared to

refer—section 172(b)/172(c)(5) (new

source review) and section 181(a)(1)/182

(classified ozone nonattainment area

requirements)—by their terms apply to

a nonattainment ‘‘area.’’ In contrast,

section 110(a)(2)(D) refers to only

‘‘nonattainment,’’ not to a

nonattainment ‘‘area.’’

By the same token, section 176A(a)

authorizes EPA to establish a transport

region whenever ‘‘the Administrator has

reason to believe that the interstate

transport of air pollutants from one or

more States contributes significantly to

a violation of a [NAAQS] in one or more

other States.’’ This reference to ‘‘a

violation of a [NAAQS]’’ makes clear

that EPA is authorized to form a

transport region when an upwind State

contributes significantly to a downwind

area with nonattainment air quality,

regardless of whether the downwind

area is designated nonattainment. The

EPA believes that section 110(a)(2)(D)

should be read the same way in light of

the parallels between section

110(a)(2)(D) and section 176A(a). Both

provisions address transport and both

are triggered when emissions from an

upwind area ‘‘contribute significantly’’

downwind. It seems reasonable to apply

a consistent approach to the type of

affected downwind area, which would

mean interpreting the term

‘‘nonattainment’’ in section 110(a)(2)(D)

as synonymous with the phrase ‘‘a

violation of a [NAAQS]’’ in section

176A(a). The CAA contains other

provisions, as well, that refer to the

factual, air quality status of a particular

area as opposed to its designation status.

These provisions include, among others,

(i) sections 172(c)(2) and 171(1), the

reasonable further progress requirement,

which requires nonattainment SIPs to

provide for ‘‘such annual incremental

reductions in emissions * * * as * * *

may * * * be required * * * for the

purpose of ensuring attainment of the

[NAAQS]’’ (emphasis added); and (ii)

section 182(c)(2), the attainment

demonstration requirement, which

mandates a ‘‘demonstration that the

[SIP] * * * will provide for attainment

of the [NAAQS]’’ (emphasis added). The

emphasized terms clearly refer to air

quality status. In a series of notices in

the Federal Register, EPA relied on

these references to air quality status in

determining that areas seeking to

redesignate from nonattainment to

attainment did not need to complete

ROP SIPs or attainment

demonstrations—even though those

requirements generally applied to areas
57372 Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations

19Similarly, EPA believes that the term

‘‘maintenance’’ in another clause of section

110(a)(2)(D)(i)(I) refers to air quality status as well.

This clause includes only the term ‘‘maintenance,’’

and does not include the term ‘‘area.’’

20See ‘‘Re-issue of the Early Planning Guidance

for the Revised Ozone and Particulate Matter (PM)

National Ambient Air Quality Standards

(NAAQS),’’ memorandum from Sally L. Shaver,

dated June 16, 1998.

21Section 110(a)(2)(D) provides that areas

designated nonattainment must submit SIPs in

accordance with ‘‘part D’’ (which includes section

172). Section 172(b) requires EPA to establish a

schedule for designated nonattainment areas to

meet the requirements of sections 172(c) and

designated nonattainment—as long as

the air quality for those redesignating

areas was, in fact, in attainment. See

‘‘State Implementation Plans; General

Preamble for the Implementation of

Title I of the Clean Air Act Amendments

of 1990; Proposed Rule,’’ 57 FR 13498,

13564 (April 16, 1992); ‘‘Determination

of Attainment of Ozone Standard for

Salt Lake and Davis Counties, Utah, and

Determination Regarding Applicability

of Certain Reasonable Further Progress

and Attainment Demonstration

Requirements: Direct Final Rule,’’ 60 FR

30189, 30190 (June 8, 1995); and

‘‘Determination of Attainment of Ozone

Standard for Salt Lake and Davis

Counties, Utah, and Determination

Regarding Applicability of Certain

Reasonable Further Progress and

Attainment Demonstration

Requirements: Final Rule,’’ 60 FR

36723, 36724 (July 18, 1995). The EPA’s

interpretation was upheld by the Court

of Appeals for the 10th Circuit, in Sierra

Club v. EPA, 99 F.3d 1551, 1557 (10th

Cir. 1996).

Accordingly, EPA believes it clear

that the reference in section

110(a)(2)(D)(i)(I) to ‘‘nonattainment’’

refers to air quality, not designation

status. The EPA believes this matter is

clearly resolved by reference to the

terms of the provision itself, so that

under the first step of the Chevron

analysis, no further inquiry is needed.

If, however, it were concluded that the

provision is ambiguous on this point,

then EPA believes that, under the

second step in the Chevron analysis,

EPA should be given deference for any

reasonable interpretation. Interpreting

‘‘nonattainment’’ to refer to air quality is

reasonable for the reasons described

above.19

The structure of the schedules for

requiring SIP submissions and

designating areas nonattainment

provides support for EPA’s

interpretation. As noted above, section

110(a)(1) requires States to submit SIPs

covering all their areas—regardless of

whether designated, or how

designated— within 3 years of a

NAAQS revision and requires that those

SIPs include provisions meeting the

requirements of section 110(a)(2)(D).20

When a new or revised NAAQS is

promulgated, section 107(d)(1)

authorizes a process of up to 3 years for

designations. States must recommend

designations within one year of

promulgation of a new or revised

NAAQS and EPA must designate areas

within 2 years of promulgation; EPA

may take up to 3 years to designate areas

if insufficient information prevents

designations within 2 years. In the case

of the 8-hour ozone NAAQS, Congress

provided specific legislation for

designations (Pub. L. 105–178 § 6103).

Under this new legislation, States are

provided 2 years to make

recommendations and EPA must

designate areas within 1 year of the time

State recommendations are due.

Because of this legislation, designations

must occur 3 years following

promulgation of the NAAQS (July 2000).

The EPA believes that it is not sensible

to interpret the term ‘‘nonattainment’’ in

section 110(a)(2)(D)(i)(I) to refer to

nonattainment designations because

those designations may not be made

until 3 years after the promulgation of

a new or revised NAAQS, and the

section 110(a)(2)(D) submittals are due

within 3 years.

Further, interpreting the reference to

‘‘nonattainment’’ as a reference to air

quality, and not designation, is

consistent with the air quality goals of

section 110(a)(2)(D) and the CAA as a

whole. In the present case, it is clear

from air quality monitoring and

modeling that large areas of the eastern

part of the United States are in violation

of the 8-hour NAAQS, and it is also

clear from air quality modeling studies

that NOX emissions from sources in

upwind States contribute to those air

quality violations. The EPA currently

has available all the information that it

needs to determine whether upwind

States should be required to revise their

SIPs to implement appropriate

reductions in NOX emissions. The

designation process will clarify the

precise boundaries of the downwind

areas, but because ozone is a regional

phenomenon, information as to the

precise boundaries of the downwind

areas is not necessary to implement the

requirements of section 110(a)(2)(D)(i).

As a result, no air quality purpose will

be served by waiting until the

downwind areas are designated

nonattainment.

On the contrary, taking action now is

necessary to protect public health. As

described in Section I.G., the regional

NOX reductions required under today’s

action will allow numerous areas

currently in violation of the 8-hour

NAAQS to attain that standard. For the

millions of people living in those areas,

today’s action will advance the date by

which these areas will meet the revised

ozone standard. Taking action now is

particularly important because one of

the sub-population groups at higher risk

to ozone health effects is children who

are active and spend more time

outdoors during the summer months

when ozone levels are elevated.

(3) EPA’s Authority to Require Section

110(a)(2)(D) Submissions in Accordance

with section 110(a)(1). Commenters

argue that sections 110(a)(1), (a)(2), and

172(b) should be read so that only

requirements under section 110(a)(2)

that are unrelated to nonattainment are

due under the section 110(a)(1)

timetable. These commenters contend

that requirements under section

110(a)(2) that are related to

nonattainment—including section

110(a)(2)(D)—are due under the section

172(b) timetable, that is, within 3 years

of the designation of areas as

nonattainment. In support, these

commenters rely on language in section

110(a)(1) indicating that the

submissions are for plans for air quality

regions ‘‘within such State.’’ Finally,

certain commenters cite as further

support for their position the definition

of the term ‘‘nonattainment’’ as found in

section 107(d)(1)(A), claiming that the

definition includes interstate transport

areas.

As noted above, section 110(a)(1)

provides that States must submit SIP

revisions providing ‘‘for the

implementation, maintenance and

enforcement’’ of the NAAQS in each

area of the State within 3 years (or a

shorter time prescribed by the

Administrator) following promulgation

of a new or revised NAAQS. Section

110(a)(2) then sets forth the applicable

elements of a SIP. These provisions

apply to all areas within the State,

regardless of designation. Section 172(b)

establishes a SIP submission schedule

for nonattainment areas. It provides that

at the time EPA designates areas as

nonattainment, EPA shall establish a

SIP submission schedule for the

submission of a SIP meeting the

requirements of section 172(c).

While EPA agrees that there is overlap

between the submission requirements

under sections 110(a)(1)–(2) and 172(c),

EPA believes that the plain language of

section 110(a)(1)–(2) authorizes EPA to

require the section 110(a)(2)(D) SIPs on

the schedule described today, and that

there is nothing to the contrary in

section 172. Sections 110(a)(2) and 172

contain cross-references to each other.21
Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations 57373

110(a)(2); section 172(c)(7) requires that

nonattainment SIPs shall meet the requirements of

section 110(a)(2).

22 In other situations, EPA has indicated that

certain elements of section 110(a)(2) would be

better addressed in accordance with the timeframe

established in section 172. See e.g., 60 FR 12492,

12505 (March 7, 1995) Proposed Requirements for

Implementation Plans and Ambient Air Quality

Surveillance for Sulfur Oxides (Sulfur Dioxide)

National Ambient Air Quality Standard.

These cross-references indicate that

under certain circumstances, the section

110(a)(2)(D) submittal may be required

under section 110(a)(1); and under other

circumstances, the section 110(a)(2)(D)

submittal may be required under section

172(b). These cross-references are

particularly relevant with respect to

nonattainment areas, which are subject

to both sections 110(a) (1) and (2) and

172. In the current situation, EPA

believes that it is appropriate to require

the submissions to meet section

110(a)(2)(D) in accordance with the

schedule in section 110(a)(1) rather than

under the schedule for nonattainment

areas in section 172(b).22

The EPA has provided that, for the

revised ozone and particulate matter

NAAQS, States must assess their section

110 SIPs by July 18, 2000 to ensure that

they adequately provide for

implementing the revised standards. See

Re-issue of the Early Planning Guidance

for the Revised Ozone and Particulate

Matter (PM) National Ambient Air

Quality Standards (NAAQS),

memorandum from Sally L. Shaver,

dated June 16, 1998. The EPA

recognized that the section 110 SIP

should generally be sufficient to address

the revised NAAQS. However, the

Agency noted three areas that the States

particularly needed to assess, including

whether the SIP adequately addressed

section 110(a)(2)(D). The EPA also

provided that the States should submit

revisions to address section 110(a)(2)(D)

on the timeframe established by the

final NOX SIP call, when issued. The

submittal date that EPA has specified in

the final NOX SIP call rule is consistent

with both the Early Planning Guidance

and with section 110(a)(1) and (2) of the

CAA.

The EPA acknowledges that it has not

historically required an affirmative

submission under section 110(a)(2)(D),

applicable to specific sources of

emissions, in response to the

promulgation of a new or revised

NAAQS. In part, this is because

sufficient technical information was not

available to determine which sources

‘‘contribute significantly’’ to

nonattainment in a downwind area. In

the absence of such a determination,

States were unable to regulate sources

under this provision in any meaningful

way. However, based on the many

analyses performed over the last several

years, EPA believes that there is now

affirmative information regarding

significant contribution to ozone

violations in the eastern portion of the

country; in light of that evidence, it

would not be appropriate to defer action

under section 110(a)(2)(D) until a later

time.

Moreover, as noted above, the section

172(c) SIP submissions apply only to

areas designated nonattainment.

Specifically, section 172(b) provides

that ‘‘[a]t the time’’ EPA designates an

area as nonattainment, EPA shall set a

schedule ‘‘according to which the State

containing such area shall submit’’ SIPs.

Section 171(2) provides further

clarification by providing that for

purposes of part D of title I of the CAA

(CAA sections 171–193) ‘‘[t]he term

‘nonattainment area’ means, for any air

pollutant, an area which is designated

‘nonattainment’ with respect to that

pollutant within the meaning of section

107(d).’’ By its terms then, section 172

does not apply to areas designated

attainment or unclassifiable (even if

such areas are not attaining the

standard) or for areas not yet designated.

Thus, section 110(a)(1) provides the

only submission schedule for areas not

designated nonattainment. For those

areas, the commenters’ argument that

section 172(b) should establish the

timetable for section 110(a)(2)(D)(i) SIPs

clearly fails. Since certain portions of

the 23 jurisdictions covered by this rule

likely will not be designated

nonattainment for the 8-hour standard,

EPA believes that the section 110(a)(1)

schedule is the only schedule (and thus

is the reasonable schedule) to follow for

purposes of the SIP call.

Furthermore, contrary to the

commenters’ assertions, the definition

of nonattainment does not broadly

include areas that contribute to

nonattainment in a downwind State.

The definition of nonattainment

includes areas that have monitored

violations of the standard and areas that

‘‘contribute to ambient air quality in a

nearby area’’ that is violating the

standard (section 107(d)(1)(A)(i)

(emphasis added)). Thus, only ‘‘nearby’’

areas that contribute to violations of a

standard will be included in the

nonattainment designation; areas

contributing to longer-range transport

will not be designated nonattainment

based solely on that longer-range

transport. Therefore, they will not be

subject to section 172(c) requirements

and timing.

The commenters argue that EPA’s

position that section 110(a)(1) governs

the section 110(a)(2)(D) SIP submittal

schedule leads to the absurd result that

upwind areas will be required to submit

SIPs dealing with their contribution to

a nonattainment problem downwind

before the downwind area will be

required to submit SIPs under section

172(b). The commenters explain that

section 110(a)(2) requires SIP submittals

on a faster timetable (within 3 years

from the date of promulgation or

revision of a NAAQS) than section

172(b) (within 3 years from the date of

designation as nonattainment). The

commenters also contend that section

107 provides that States have the

primary responsibility for ensuring

attainment within their boundaries;

only after a State implements all

statutorily required and necessary

measures can it pursue reductions in

other areas through a SIP call or section

126. The commenters contend that the

SIP call is contrary to the plain language

of section 107 and congressional intent

because it would require upwind areas

to implement controls before the

downwind area has implemented all

statutorily required or necessary

controls.

While it is true that plans to meet the

emissions budget for the SIP call will be

due prior to nonattainment designations

and attainment plans for areas

designated nonattainment for the 8-hour

standard, EPA does not consider this

result to be absurd in the present case.

The CAA, at least since its

amendment in 1970, has required States

to regulate ozone. For more than the

past 25 years, States have focused on the

adoption and implementation of local

controls for the purpose of bringing

nonattainment areas into attainment.

Thus, historically, the downwind

nonattainment areas have borne the

brunt of the control obligations through

the implementation of local controls. In

comparison, areas in attainment of the

NAAQS, but upwind of nonattainment

areas, have not been required to

implement controls designed to

ameliorate the air quality problems

experienced by their downwind

neighbors.

Since the CAA Amendment of 1977,

designated nonattainment areas have

been subject to specific local control

obligations, such as vehicle I/M and, for

stationary sources, the requirement to

implement RACT. The CAA

Amendments of 1990 tightened these

control obligations for many areas.

Moderate, serious, severe and extreme

areas were required to reduce emissions

by 15 percent between 1990 and 1996.

In addition, each serious, severe and

extreme area is required to achieve 9

percent reductions over the succeeding

3 year periods until the area attains the
57374 Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations

23Although the SIP call will provide a benefit to

a wide number of areas, the focus of the SIP call

is to reduce boundary conditions for a number of

areas that will have difficulty attaining either the 1-

hour or 8-hour standard (or both) without the

benefit of reductions from outside the

nonattainment area. Based on current monitoring

data and modeling, EPA predicts that there will be

a number of areas that are meeting the 1-hour

standard that will be designated nonattainment for

the 8-hour standard. The EPA further predicts that

many of these areas will come back into attainment

due solely to the emission reductions achieved by

the NOX SIP call. However, this incidental benefit—

which likely will occur without the need for local

emission reductions—does not preclude EPA from

requiring the SIP call reductions, which are needed

to help other more seriously polluted areas that

have long-standing pollution problems.

24Maine, New Hampshire, and Vermont are the

only downwind States that are not subject to

today’s action.

standard. Additional requirements, such

as the use of RFG and the use of vapor

recovery devices on gasoline pumps, are

also required for certain areas (see

generally, CAA section 182 and, e.g.,

section 211(k)). Thus, downwind areas

with nonattainment problems under the

1-hour NAAQS are under current

obligations to submit SIP revisions

containing local control measures for

that standard. For these areas, local

reductions needed to meet the 1-hour

standard are already occurring and will

be achieved prior to or on the same

schedule as reductions States may

require in response to the SIP call.

Furthermore, in many of the

downwind areas, States have been

taking action to reduce ozone levels for

many years in order to meet the 1-hour

ozone NAAQS. Although the fact that

the 8-hour ozone NAAQS is a new form

of the ozone standard, however, should

not obscure the fact that the downwind

States have been making efforts to

reduce ozone levels for decades. The

EPA believes that the history of

implementation by downwind areas of

ozone pollution controls further

mitigates the commenters’ argument

that it is absurd to require upwind areas

to implement controls in advance of

downwind attainment demonstrations

under the 8-hour NAAQS.23

Moreover, virtually all of the

downwind States affected by today’s

rulemaking, due to 8-hour ozone

nonattainment or maintenance

problems, are themselves upwind

contributors to problems further

downwind, and, thus, are subject to the

same requirements as the States further

upwind.24 The reductions these

downwind States must implement due

to their additional role as upwind States

will help reduce their own 8-hour ozone

problems on the same schedule as

emissions reductions for the upwind

States. Accordingly, for the most part,

this rulemaking does not require

upwind areas to take action in advance

of any action by downwind areas to

ameliorate the downwind problems.

Finally, even if EPA were requiring

upwind States to take action to reduce

downwind nonattainment and

maintenance in advance of action by the

downwind States, this would simply

require upwind areas to take the first

step by developing SIPs to eliminate

their significant contribution to the

downwind problem. The downwind

areas will be required to take the next

step by developing SIPs that address

their share. Generally, an agency may

resolve a problem (in this case,

downwind nonattainment) on a step-bystep basis (see e.g., Group Against Smog

and Pollution, Inc. v. EPA, 665 F.2d

1284, 1291–92 (D.C. Cir. 1981)).

A commenter has observed that under

section 110(a)(1), EPA may authorize

section 110(a)(2) submittals as late as 3

years after revision of a NAAQS, which,

in this case, would run until July 2000.

The Early Planning Guidance, described

above, indicates that States are allowed

until July 2000 to make submissions

concerning other elements of section

110(a)(2). However, as described

elsewhere, EPA has determined that the

section 110(a)(2)(D) submittals should

be submitted by the end of September

1999 to assure that the required NOX

reductions will be implemented as

expeditiously as practicable, which EPA

has determined is no later than the May

1 start of the 2003 ozone season (see

Section V, below).

Citing section 107(a) of the CAA, the

commenters assert that the CAA

requires downwind areas to fully adopt

and implement all statutorily required

or necessary measures before EPA can

require upwind areas to control

emissions. Section 107 provides that

States shall have the primary

responsibility for assuring air quality

within the State by submitting a plan

that specifies how the NAAQS will be

achieved and maintained in the State.

The commenters attempt to read this

statement regarding a State’s authority

to choose the mix of control measures

within State boundaries as barring the

control of emissions from upwind

States.

This provision may be read as

focusing on the State-Federal balance in

controlling criteria pollutants, such as

ozone, not any upwind-State,

downwind-State balance. The provision

indicates that although EPA may

promulgate Federal measures that

provide reductions to help States reach

attainment, States bear the ultimate

responsibility for assuring attainment.

Further, this provision may be read to

indicate that States may choose the mix

of controls to reach attainment within

their own boundaries. Nothing in this

provision purports to address the need

for upwind controls. By comparison,

section 110(a)(2)(D) affirmatively

requires States to submit a SIP

prohibiting emissions that significantly

contribute to downwind nonattainment

or interfere with maintenance of the

NAAQS. Thus, the statute, read as a

whole, contemplates that interstate

transport will be addressed as part of

the downwind States’ attainment

responsibilities. Indeed, determining the

upwind area’s share of the problem is

necessary in order for downwind

attainment planning. In the absence of

the upwind reductions that will be

achieved, the downwind area would be

required to submit an attainment plan to

demonstrate attainment regardless of

cost and without benefit of the

reduction of upwind emissions that

significantly contribute to

nonattainment. In light of the statute as

a whole, it is absurd to argue that

Congress intended downwind areas to

reduce emissions at any cost while

upwind sources that significantly

contribute to that nonattainment remain

unregulated. Congress attempted to

balance responsibilities, providing that

States could choose the mix of controls

within the State’s borders (CAA section

107(a)) and are ultimately responsible

for assuring attainment, but also

recognizing that emissions reductions

from upwind States may be needed for

attainment (CAA section 110(a)(2)(D)(i)).

b. Process for Requiring SIP

Submissions under the 8-Hour

Standard. The time by which the

section 110(a)(2)(D) SIP revision under

the 8-hour NAAQS must be submitted is

governed by section 110(a)(1), which

requires the SIP revision to be

‘‘adopt[ed] and submit[ed] to the

Administrator, within 3 years (or such

shorter period as the Administrator may

prescribe) after the promulgation of a

[NAAQS] (or any revision thereof) . . .

.’’ In the NPR, EPA indicated that the

SIP revision would be due by the end

of September 1999, which EPA expected

to be 12 months from the date of

completing today’s final rule. In today’s

action, EPA is confirming that the SIP

revision will be due September 30,

1999, for the reasons described below in

Section VI.A.1, Schedule for SIP

Revision.

3. Requirements of Section 110(a)(2)(D)

a. Summary. Today’s action is driven

by the requirements of CAA section

110(a)(2)(D). This provides that each SIP

must—
Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations 57375

25 It should be reiterated that EPA relied on the

designated area solely as a proxy to determine

which areas have air quality in nonattainment. This

proxy is readily available under the 1-hour NAAQS

because areas have long been designated

nonattainment. The EPA’s reliance on designated

nonattainment areas for purposes of the 1-hour

NAAQS does not indicate that the reference in

section 110(a)(2)(D)(i)(I) to ‘‘nonattainment’’ should

be interpreted to refer to areas designated

nonattainment.

* * * contain adequate provisions—(I)

prohibiting, consistent with the provisions of

this title, any source or other type of

emissions activity within the State from

emitting any air pollutant in amounts which

will—(I) contribute significantly to

nonattainment in, or interfere with

maintenance by, any other State with respect

to any such national primary or secondary

ambient air quality standard * * *

According to section 110(a)(2)(D), the

SIP for each area, regardless of its

designation as nonattainment or

attainment (including unclassifiable),

must prohibit sources within the area

from emitting air pollutants in amounts

that will ‘‘contribute significantly’’ to

‘‘nonattainment’’ in a downwind State,

or that ‘‘interfere with maintenance’’ in

a downwind State.

b. Determination of Meaning of

‘‘Nonattainment’’ (1) Geographic Scope.

In determining the meaning and scope

of section 110(a)(2)(D), it is useful first

to determine the geographic scope of

‘‘nonattainment’’ downwind.

At proposal, EPA stated that it—

* * * proposes to interpret this term to

refer to air quality and not to be limited to

currently-designated nonattainment areas.

Section 110(a)(2)(D) does not refer to

‘‘nonattainment areas,’’ which is a phrase

that EPA interprets to refer to areas that are

designated nonattainment

under * * * section 107(d)(1)(A)(I) * * * .

Rather, the provision includes only the term

‘nonattainment’ and does not define that

term. Under these circumstances, EPA has

discretion to give the term a reasonable

definition, and EPA proposes to define it to

include areas whose air quality currently

violates the NAAQS, and will likely continue

[to violate in the future], regardless of the

designation of those areas * * *

(62 FR 60324).

To determine whether areas would

continue to violate in the future, EPA

proposed to take into account the

reductions that would result from

current CAA control requirements (apart

from controls that may be required

under section 110(a)(2)(D)). To take

these reductions into account, EPA

determined whether the area would be

in nonattainment in the future based on

air quality modeling that assumed CAAmandated reductions and that

accounted for growth. If an area would

reach attainment based on required

controls, EPA would not view that area

as having a nonattainment problem to

which any upwind areas may be

considered to contribute.

As explained earlier, in today’s

action, EPA has determined that for

purposes of the 8-hour NAAQS, the

reference to ‘‘nonattainment’’ should be

defined as EPA proposed. Thus, in

determining whether an upwind area

contributes significantly to

‘‘nonattainment’’ downwind, EPA

would evaluate downwind areas for

which monitors indicate current

nonattainment, and air quality models

indicate future nonattainment, taking

into account CAA control requirements

and growth.

For the 1-hour standard, EPA

proposed to define nonattainment to

include all grid cells within a county

when a monitor in that county indicated

nonattainment. Upon further study, EPA

found that in some instances, a

metropolitan area may consist of

numerous counties, only a few of which

contain monitors indicating

nonattainment. The EPA recognizes that

under the 1-hour NAAQS,

nonattainment boundaries are generally

used to describe the area with the

nonattainment problem; accordingly,

EPA believes that this geographic

vicinity offers an appropriate indication

of an area that may be expected to have

nonattainment air quality. The EPA

predicts that many 1-hour

nonattainment areas that currently

monitor nonattainment somewhere

within the area will remain in

nonattainment in 2007, in some cases

because of predicted violations in

counties that currently monitor

attainment. The EPA believes that the

entire area should be considered to be

in nonattainment until all monitors in

the area indicate attainment of the

NAAQS. Thus, in today’s action, EPA

used the designated nonattainment area

in determining the downwind

nonattainment problem.25

As noted above, commenters

disagreed with EPA’s view that the term

‘‘nonattainment’’ covers areas with air

quality that is currently in

nonattainment, regardless of

designation. The EPA’s response to

those comments is also set forth above.

(2) 2007 Projection Year. In the NPR,

EPA indicated that it would adopt the

year 2007 as the year for determining

whether areas achieved their required

NOX budget levels. Accordingly, in

determining whether downwind areas

should be considered to be, and remain

in, ‘‘nonattainment,’’ EPA would model

their air quality in 2007, based on the

implementation of CAA required

controls by that date, and growth in

emissions—generally due to economic

growth and greater use of vehicles—by

that date. At proposal, EPA adopted this

same approach with respect to both the

1-hour and the 8-hour NAAQS (62 FR

60325). The EPA is continuing this

approach.

c. Definition of Significant

Contribution. As indicated in the NPR,

neither the CAA nor its legislative

history provides meaningful guidance

for interpreting the term ‘‘contribute

significantly’’ under section

110(a)(2)(D)(i)(I).

(1) ‘‘Contribute.’’ The initial step in

defining the ‘‘contribute significantly’’

term is to determine the meaning of the

term ‘‘contribute.’’ In the NPR, EPA

stated that it believes this term should

be defined broadly, so that emissions

‘‘contribute’’ to nonattainment

downwind if they have an impact on

nonattainment downwind (62 FR

60325). Air quality modeling indicated

that emissions from the upwind States

clearly impact downwind

nonattainment problems; as a result,

EPA generally folded this step of

determining whether sources

‘‘contribute’’ to nonattainment

downwind into the step of determining

whether that contribution is

‘‘significant,’’ discussed below.

In addition, section 110(a)(2)(D)(i)(I)

requires the SIP to prohibit amounts of

emissions ‘‘which will contribute

significantly * * *’’ (emphasis added).

The EPA believes that the term ‘‘will’’

means that SIPs are required to

eliminate the appropriate amounts of

emissions that presently, or that are

expected in the future, contribute

significantly to nonattainment

downwind.

Because ozone is a secondary

pollutant formed as a result of complex

chemical reactions involving numerous

sources, it is not possible to determine

the downwind impact on each

individual source. In addition, ozone

generally results from the contributions

of numerous sources. As indicated in

the NPR:

[U]nhealthful levels of ozone result from

emissions of NOX and VOCs from thousands

of stationary sources and millions of mobile

sources [and consumer products and other

sources] across a broad geographic area. Each

source’s contribution is a small percentage of

the overall problem; indeed, it is rare for

emissions from even the largest single

sources to exceed one percent of the

inventory of ozone precursors even for a

single metropolitan area. Under these

circumstances, even complete elimination of

any given source’s emissions may well have

no measurable impact in ameliorating the

nonattainment problem. Rather, attainment

requires controls on numerous sources across

a broad area. Ozone is a regional scale
57376 Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations

problem that requires regional scale

reductions

(62 FR 60326).

Accordingly, EPA has adopted a

‘‘collective contribution’’ approach to

determining whether sources

‘‘contribute’’ to nonattainment

downwind: EPA determines the impact

downwind of emissions in the aggregate

from a particular geographic region. If

the aggregated emissions are considered

to contribute to nonattainment

downwind, then all of the emissions in

that region should be considered as

contributors to that nonattainment

problem. In today’s action, EPA is

continuing the same interpretation of

the term ‘‘contribute,’’ for the reasons

just described.

(2) ‘‘Significantly’’. (a) Notice of

Proposed Rulemaking. In the NPR, EPA

proposed a ‘‘weight-of-evidence,’’ or

multi-factor, approach for determining

whether a contribution is ‘‘significant.’’

The EPA proposed two separate

interpretations for the term ‘‘contribute

significantly,’’ which had implications

as to which factors were to be

considered in what parts of the analysis.

Under the first interpretation,

significant contribution is determined

with reference to—

* * * factors concerning amounts of

emissions and their ambient impact,

including the nature of how the pollutant is

formed, the level of emissions and emissions

density (defined as amount of emissions per

square mile) in the particular upwind area,

the level of emissions in other upwind areas,

the amount of contribution to ozone in the

downwind area from the upwind areas, and

the distance between the upwind sources and

the downwind nonattainment problem.

Under this approach, when emissions and

ambient impact reach a certain level, as

assessed by reference to the factors identified

above, those emissions would be considered

to ‘‘contribute significantly’’ to

nonattainment.

(62 FR 60325).

Under this interpretation, after

identifying amounts of emissions that

constitute a significant contribution,

EPA then determines the amount of

emissions reductions necessary to

adequately mitigate these contributions.

This determination entails—

* * * [e]valuation of the costs of available

measures for reducing upwind emissions

* * * as well as to the extent known (at least

qualitatively), the relative costs of, amounts

of reductions from, and ambient impact of

measures available in the downwind areas.

Id.

Under the second interpretation, EPA

considers all of the factors under both

the significant contribution prong and

the mitigation prong of the first

interpretation, and, once EPA

determines an amount of emissions that

does significantly contribute to

downwind nonattainment, then EPA

would determine that the SIP must

contain provisions adequate to prohibit

that amount of emissions. Id. at 60325–

26.

(b) Today’s Action. The EPA has

determined that the second

interpretation should be used; that is,

that the determination of significant

contribution includes both air quality

factors relating to amounts of upwind

emissions and their ambient impact

downwind, as well as cost factors

relating to the costs of the upwind

emissions reductions. Once an amount

of emissions is identified in an upwind

State that contributes significantly to a

nonattainment problem downwind, or

interferes with maintenance downwind,

the SIP must include provisions to

eliminate that amount of emissions.

To reiterate, section 110(a)(2)(D)(i)(I)

provides that the SIP must ‘‘prohibit[]’’

sources from ‘‘emitting any air pollutant

in amounts which will contribute

significantly to nonattainment in, or

interfere with maintenance by, any

other State.’’ The term ‘‘prohibit’’ is

defined as ‘‘to forbid by authority’’ or

‘‘prevent,’’ or ‘‘preclude.’’ ‘‘The

American Heritage Dictionary of the

English Language’’ (3d ed. 1992, 1448).

The EPA believes that the term

‘‘prohibit’’ means that SIPs must

eliminate those amounts of emissions

determined to contribute significantly to

nonattainment or interfere with

maintenance downwind. Moreover, EPA

believes that whether emissions

‘‘contribute significantly’’ depends on a

multifactor test, as described below.

Thus, section 110(a)(2)(D)(i)(I) does not

require the elimination of all upwind

source emissions that impact downwind

air quality problems, but only those

amounts of emissions that, based on a

multi-factor test, significantly contribute

to downwind air quality problems.

d. Multi-factor Test for Determining

Significant Contribution. In the NPR,

EPA proposed a multi-factor test for

determining whether emissions from an

upwind State contribute significantly to

a nonattainment or maintenance

problem downwind. The EPA received

numerous comments on the factors.

Based on the comments and EPA’s

further analysis, EPA, in today’s action,

is continuing the multi-factor approach,

with some refinements in response to

comments, with respect to the factors

EPA considered and the manner in

which EPA considered them.

In determining whether emissions

from upwind States affected by today’s

action contribute significantly to

downwind nonattainment or

maintenance problems, EPA specifically

considered the following factors with

respect to each such upwind State.

These factors were the primary

components in EPA’s consideration.

fl The overall nature of the ozone

problem (i.e., ‘‘collective contribution’’)

fl The extent of the downwind

nonattainment problems to which the

upwind State’s emissions are linked,

including the ambient impact of

controls required under the CAA or

otherwise implemented in the

downwind areas

fl The ambient impact of the

emissions from the upwind State’s

sources on the downwind

nonattainment problems

fl The availability of highly cost

effective control measures for upwind

emissions.

The first three of these factors are

related to air quality; the fourth is

related to costs.

In addition, EPA generally reviewed

several other considerations before

concluding that upwind emissions

contribute significantly to downwind

nonattainment. The EPA did not

consider it necessary, or did not have

adequate information, to apply each of

these factors with specificity with

respect to each upwind State’s

emissions. In addition, in some

instances, EPA did not have quantitative

information to assess certain of these

factors, and instead relied on qualitative

information. These considerations were

secondary aspects of EPA’s analysis.

They include:

fl The consistency of the regional

reductions with the attainment needs of

the downwind areas with

nonattainment problems

fl The overall fairness of the control

regimes required of the downwind and

upwind areas, including the extent of

the controls required or implemented by

the downwind and upwind areas

fl General cost considerations,

including the relative cost-effectiveness

of additional downwind controls

compared to upwind controls

All of these factors and considerations

are described in the following sections.

e. Air Quality Factors. As noted

above, EPA specifically considered

three air quality factors with respect to

each upwind State, which factors, in

conjunction with the cost factor

discussed in the next section, were the

primary components in EPA’s

consideration:

fl The overall nature of the ozone

problem (i.e., ‘‘collective contribution’’)

fl The extent of the downwind

nonattainment problems to which the

upwind State’s emissions are linked,
Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations 57377

26The presence of residual nonattainment in

major urban areas after their implementation of

specifically required CAA controls supports the

regional reductions required under today’s action.

Those regional reductions allow the major urban

areas to progress towards attainment under the 8-

hour NAAQS, and, at the same time, significantly

ameliorate the nonattainment problems under the 8-

hour NAAQS for numerous other areas. In fact, EPA

projections indicate that numerous areas with

nonattainment problems will achieve attainment of

the 8-hour NAAQS as a result of the regional

reductions.

including the ambient impact of

controls required under the CAA or

otherwise implemented in the

downwind areas

fl The ambient impact of the

emissions from the upwind State’s

sources on the downwind

nonattainment problems

(1) Collective Contribution. As

indicated elsewhere, ozone generally

results from the collective contribution

of emissions from numerous sources

over a large geographic area. For

example, for urban nonattainment areas

under the 1-hour NAAQS, the

downwind sources, comprise numerous

stationary sources as well as mobile onroad sources, mobile off-road sources,

and consumer and commercial

products. Further, additional

contributions are made by numerous

upwind States, both adjacent to and

further away from the nonattainment

area itself. The fact that virtually every

nonattainment problem is caused by

numerous sources over a wide

geographic area is a factor suggesting

that the solution to the problem is the

implementation over a wide area of

controls on many sources, each of

which may have a small or

unmeasureable ambient impact by itself.

(2) Extent of Downwind

Nonattainment Problems, Including

Ambient Impact of Required Controls.

In determining whether a downwind

area has a nonattainment problem under

the 1-hour standard to which an upwind

area may be determined to be a

significant contributor, EPA determined

whether the downwind area currently

has a nonattainment problem, and

whether that area area would continue

to have a nonattainment problem as of

the year 2007 assuming that in that area,

all controls specifically required under

the CAA were implemented, and all

required or otherwise expected Federal

measures were implemented. If,

following implementation of such

required CAA controls and Federal

measures, the downwind area would

remain in nonattainment, then EPA

considered that area as having a

nonattainment problem to which

upwind areas may be determined to be

significant contributors.

Thus, this analytical approach

assumes that downwind areas

implement all required controls and

receive the benefit of reductions from

Federal measures, and yet have a

residual nonattainment problem (prior

to the implementation of the regional

reductions required by today’s action).

The fact that a nonattainment problem

persists, notwithstanding fulfillment of

CAA requirements by the downwind

sources, is a factor suggesting that it is

reasonable for the upwind sources to be

part of the solution to the ongoing

nonattainment problem.

The EPA undertook a comparable

analysis with respect to the 8-hour

NAAQS. That is, the major urban areas

in the northeast, midwest, and south

that are violating the 8-hour NAAQS are

designated nonattainment under the 1-

hour NAAQS as well. After these areas

are designated nonattainment under the

8-hour NAAQS, they will become

subject to the control requirements of

section 172(c). However, for these areas,

the section 172(c) requirements do not,

by their terms, impose any specific

controls other than what these areas

have already implemented to fulfill the

requirements under section 182

attendant to their designation and

classification under the 1-hour NAAQS.

Accordingly, the same air quality

modeling analyses that shows residual

nonattainment for at least one of the

urban areas linked to each upwind State

under the 1-hour standard shows

residual nonattainment for those areas

under the 8-hour NAAQS. Indeed,

modeling analyses relied on for today’s

action indicate residual nonattainment

for the major urban areas even after the

implementation of regional reductions

comparable to those required today.26

(3) Ambient Impact of Emissions from

the Upwind Sources. In today’s action,

EPA examined the impact of numerous

upwind States on numerous downwind

areas with nonattainment problems.

Under the 1-hour NAAQS, EPA

conducted various air quality modeling

analyses that examined the impact of

emissions from sources in each upwind

State on ozone levels in downwind

nonattainment areas, in light of the

impact of emissions from sources in

other upwind States on the downwind

area’s nonattainment problem. The EPA

assessed the frequency and magnitude

of each upwind State’s contribution to

downwind nonattainment problems.

Some of the modeling analyses also

permitted determining the magnitude of

the average contribution and the peak

contribution from each upwind State, as

well as the percentage of each upwind

State’s contribution to the downwind

nonattainment problem.

The EPA determined that for each

upwind State affected by today’s action,

its contribution to a downwind

nonattainment problem, in conjunction

with the contribution from other

upwind States, comprised a relatively

large percentage of the nonattainment

problem. The EPA further determined

that, in this context, the impacts from

each affected upwind State’s NOX

emissions are sufficiently large and/or

frequent so that the amounts of that

State’s emissions should be considered

to be significant contributions,

depending on the cost factor and other

relevant considerations. For most

upwind States, EPA conducted two

types of modeling—UAM–V and

CAMx—that isolated the impact of

emissions from the upwind State alone

on downwind nonattainment.

The EPA also conducted much the

same analysis to determine the impact

of emissions from each upwind State on

ozone levels in downwind States under

the 8-hour NAAQS. Because

nonattainment problems under the 8-

hour NAAQS are widespread, and

because EPA has not designated

individual nonattainment areas, EPA

focused this part of its inquiry on the

upwind State’s impact on the entire

downwind State.

The EPA’s analysis under both the 1-

hour and 8-hour NAAQS led EPA to

conclude that, in light of both the

collective contribution nature of the

ozone problem, and the fact that

downwind areas continue to suffer a

nonattainment problem even after

implementation of all required CAA

measures and Federal measures,

emissions from each of the affected

upwind States have a sufficiently large

and/or frequent ambient impact such

that those emissions contribute

significantly to nonattainment

downwind, depending on the

availability of highly cost-effective

measures and on other considerations

discussed below.

f. Determination of Highly Costeffective Reductions and of Budgets.

After determining the degree to which

NOX emissions, as a whole from the

particular upwind States, contribute to

downwind nonattainment or

maintenance problems, EPA then

determined whether any amounts of the

NOX emissions may be eliminated

through controls that, on a cost-per-ton

basis, may be considered to be highly

cost effective. By examining the cost

effectiveness of recently promulgated or

proposed NOX controls, EPA

determined that an average of

approximately $2,000 per ton removed
57378 Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations

27As indicated in the NPR, EPA considers that

measures may be reasonable in light of their

reduction of VOC and NOX emissions, even though

their cost-effectiveness in terms of cost per NOX

emissions removed is relatively high (62 FR 60346–

48).

is highly cost effective. The EPA then

determined a set of controls on NOX

sources that would cost no more than an

average of $2,000 per ton reduced.

Specifically, EPA determined that one

set of these controls would include a

cap-and-trade program for (i) electricity

generating boilers and turbines larger

than 25 Mwe (‘‘large EGUs’’), and (ii)

large non-electricity generating

industrial boilers and turbines (‘‘large

non-EGU boilers and turbines’’). The

application of an emission rate of 0.15

lb/mmBtu and 1995–1996 utilization for

EGUs and 60 percent for large non-EGUs

to the emissions projected to occur in

2007 including growth and CAA

measures, led to the determination of

the amounts to be reduced. The

remaining amount is a State’s budget.

The EPA further determined that

additional highly cost-effective controls

are also available for cement

manufacturing sources and internal

combustion engines. On the basis of

reasonable assumptions concerning

growth to the year 2007, EPA then

determined the amounts of emissions

from these source categories that would

be eliminated with those controls.

The EPA further determined that

there were no other controls on other

NOX sources that qualify as highly cost

effective (although several controls are

reasonably cost-effective).

On the basis of the determinations

just described for the various source

categories, EPA determined an amount

of NOX emissions that may be

eliminated through these highly costeffective measures. Because EPA had

also determined that the NOX emissions

from the affected upwind States have a

large and/or frequent impact on

downwind nonattainment or

maintenance problems, EPA concludes

that the amount of NOX emissions from

those States that can be eliminated

through application of highly costeffective control measures contributes

significantly to nonattainment or

maintenance problems downwind.

Under section 110(a)(2)(D)(i)(I), the

SIP must include ‘‘adequate provisions

prohibiting’’ sources from emitting these

‘‘amounts.’’ Because no highly costeffective controls are available to

eliminate the remaining amounts of

NOX emissions, EPA concludes that

those emissions do not contribute

significantly to downwind

nonattainment or maintenance

problems. As indicated below and in

Section III, there are cost-effective

alternatives available to States that

choose not to adopt all of the highly

cost-effective measures on which EPA

based its selection of the significant

amounts of NOX emissions.

To implement EPA’s determinations,

each affected upwind State is required

to submit for EPA approval SIP controls

projected to be sufficient, by the year

2007, to eliminate the amount of NOX

emissions in the State that EPA

determined contributes significantly to

nonattainment. The EPA determined

this amount of reductions, for each

affected upwind State, as follows: EPA

first determined the amount of NOX

emissions in that State by the year 2007,

based on assumptions concerning both

growth and emissions controls that are

required under the CAA or that will be

implemented due to Federal actions (the

‘‘2007 base case’’). Second, EPA applied

the control measures identified as

highly cost effective to the 2007 base

case amount for the appropriate source

categories. The amount of NOX

emissions remaining in the State after

application of controls to the affected

source categories constitutes the 2007

budget. The difference between the 2007

base case and the 2007 budget is the

amount of NOX emissions in that State

by the year 2007 that EPA has

determined to contribute significantly to

nonattainment and that, therefore, the

SIPs must prohibit.

The upwind State’s SIP revision due

in response to today’s action must

provide controls that, on the basis of the

same assumptions (including

concerning growth) made by EPA in

determining the budget, would limit

NOX emissions in the year 2007 to no

more than the 2007 budget. The State

has full discretion in selecting the

controls, so that it may choose any set

of controls that would assure

achievement of the budget.

As EPA stated in the NPR:

States are not constrained to adopt

measures that mirror the measures EPA used

in calculating the budgets. In fact, EPA

believes that many control measures not on

the list relied upon to develop EPA’s

proposed budgets are reasonable—especially

those, like enhanced vehicle inspection and

maintenance programs, that yield both NOX

and VOC emissions reductions.[ 27] Thus, one

State may choose to primarily achieve

emissions reductions from stationary sources

while another State may focus emission

reductions from the mobile source sector.

(62 FR 60328).

The EPA believes that its overall

approach derives further support from

the mandate in section 110(a)(2)(D) that

each SIP include provisions prohibiting

‘‘any source or other type of emissions

activity within the State from emitting

any air pollutant in amounts’ that

adversely affect downwind areas. The

phrase ‘‘any source or other type of

emissions activity’’ may be interpreted

to require that the SIP regulate all

sources of emissions to assure that the

total amount of emissions generated

within the State does not adversely

affect downwind areas. By its terms, the

phrase covers all emitters of any kind

because every emitter—stationary,

mobile, or area—may be considered a

‘‘source or other type of emissions

activity.’’ This interpretation is

consistent with the legislative history of

the phrase. Prior to the CAA

Amendments of 1990, the predecessor

to section 110(a)(2)(D), which was

section 110(a)(2)(E), referred to ‘‘any

stationary source within the State.’’ In

the 1990 Amendments, Congress revised

the phrase to read as it currently does.

A Committee Report explained, ‘‘Where

prohibitions in existing section

110(a)(2)(E) apply only to emissions

from a single source, the amendment

includes ‘‘any other type of emissions

activity,’’ which makes the provision

effective in prohibiting emissions from,

for example, multiple sources, mobile

sources, and area sources.’’ V Leg. Hist.

8361, S. Rep. No. 228, 101st Cong., 1st

Sess. 21 (1989).

For reasons explained below, if an

upwind State chooses to achieve all or

a portion of the required reductions

from large EGUs or large non-EGU

boilers and turbines, then the SIP must

include a mass emissions limitation for

those sources computed with reference

to certain growth assumptions and the

emission rate limits chosen by the State.

The EPA recommends that this mass

limitation, or cap, be accompanied by a

trading program. Any such cap-andtrade program must be established by

May 1, 2003. If the State chooses to

achieve all or a portion of the required

reductions from other sources, then the

State must implement controls, by the

year 2003, on those other sources that

are projected to achieve the required

level of reductions, based on certain

assumptions (including growth), in the

year 2007. The controls on these other

sources may be rate-based, and no

emissions cap on them is required. By

the year 2007, any applicable mass

emissions limitation for large EGUs or

large non-EGU boilers and turbines

must continue to be met, and any

applicable controls on other sources

must continue to be implemented. The

amount of the 2007 overall budget is

used to compute the level of controls

that would result in the appropriate

amount of emissions reductions, given

assumptions concerning, for example,
Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations 57379

growth. To this extent, the 2007 overall

budget is an important accounting tool.

However, the State is not required to

demonstrate that it has limited its total

NOX emissions to the budget amounts.

Thus, the overall budget amount is not

an independently enforceable

requirement.

g. Other Considerations in

Determination of Significant

Contribution. The EPA reviewed several

other considerations in support of its

determination that the specified

amounts of emissions from the affected

upwind States contribute significantly

to nonattainment downwind.

(1) Consistency of Regional

Reductions with Downwind Attainment

Needs. The EPA conducted modeling

analyses of emission reductions of

virtually the same magnitude as the

regional reductions required under

today’s action. Although the impact on

any downwind ozone problem of each

upwind State’s emissions reductions

alone may be relatively small, the

impact of those reductions, when

combined with the reductions from the

other States, is substantial. Based on

this modeling, EPA determined that the

regional reductions allow downwind

nonattainment areas under the 1-hour

NAAQS to make appreciable progress

towards attainment. The EPA further

determined that under the 8-hour

NAAQS, many areas with

nonattainment problems are expected to

reach attainment based solely on the

regional reductions, and that other

(primarily urban) areas would benefit

from the regional reductions but are

expected to experience residual

nonattainment. EPA further determined

that none of the upwind States affected

by today’s action are affected by

‘‘overkill,’’ that is, required reductions

that are more than necessary to

ameliorate downwind nonattainment in

every downwind area affected by that

upwind State.

(2) Fairness. The EPA also considered

the overall fairness of the control

regimes required of the downwind and

upwind areas, including the extent of

the controls required or implemented by

the downwind and upwind areas. Most

broadly, EPA believes that overall

notions of fairness suggest that upwind

sources which contribute significant

amounts to the nonattainment problem

should implement cost-effective

reductions. When upwind emitters

exacerbate their downwind neighbors’

ozone nonattainment problems, and

thereby visit upon their downwind

neighbors additional health risks and

potential clean-up costs, EPA considers

it fair to require the upwind neighbors

to reduce at least the portion of their

emissions for which highly costeffective controls are available.

In addition, EPA recognizes that in

many instances, areas designated as

nonattainment under the 1-hour

NAAQS have incurred ozone control

costs since the early 1970s. Moreover,

virtually all components of their NOx

and VOC inventories are subject to SIPrequired or Federal controls designed to

reduce ozone. Furthermore, these areas

have complied with almost all of the

specific control requirements under the

CAA, and generally are moving towards

compliance with their remaining

obligations. The CAA’s sanctions and

FIP provisions provide assurance that

these remaining controls will be

implemented. By comparison, many

upwind States in the midwest and south

have had fewer nonattainment problems

and have incurred fewer control

obligations.

(3) General Cost Considerations. The

EPA also considered the fact that in

general, areas that currently have, or

that in the past have had, nonattainment

problems under the 1-hour NAAQS, or

that are in the Northeast Ozone

Transport Region (OTR), have already

incurred ozone control costs. The

controls already implemented in these

areas tend to be among the less

expensive of available controls. As

described in more detail below, EPA has

determined that, in general, the next set

of controls identified as available in the

downwind nonattainment areas under

the 1-hour NAAQS would cost

approximately $4,300 per ton removed.

By comparison, EPA has determined

that the cost of the regional reductions

required today would approximate

$1,500 per ton removed. Thus, it

appears that the upwind reductions

required by today’s action are more costeffective per ton removed than

reductions in the downwind

nonattainment areas. Moreover, under

the 1-hour NAAQS, the reductions

required from each upwind State, in

conjunction with reductions from other

upwind States, result in ambient

improvement in at least several

downwind areas with nonattainment

problems.

The EPA did not have available, and

was not presented with, meaningful

quantitative information indicating the

cost-effectiveness of the regional

reductions required today in light of

their ambient impact downwind (e.g.,

the cost of emissions reductions per ppb

improvement in ambient ozone levels in

a downwind nonattainment area). This

lack of information limited the extent to

which EPA could rely on this

consideration in making its

determinations.

The various considerations just

discussed point in the same direction as

the other factors described above

concerning air quality and costs. These

factors and considerations lead EPA to

conclude that the amounts of each

upwind State’s emissions that may be

eliminated through highly cost-effective

measures contribute significantly to

nonattainment or maintenance problems

downwind.

h. Interfere with Maintenance. Once a

nonattainment area has attained the

NAAQS, it is required to maintain that

standard (e.g., sections 107(d)(3)(E)(iv),

110(a)(1)). Section 110(a)(2)(D)(i)(I) also

requires that SIPs contain adequate

provisions prohibiting amounts of

emissions that ‘‘interfere with

maintenance by * * * any [downwind]

State.’’ The EPA explained and applied

this requirement in the NPR as follows:

This [interfere-with-maintenance]

requirement * * * does not, by its terms,

incorporate the qualifier of ‘‘significantly.’’

Even so, EPA believes that for present

purposes, the term ‘‘interfere’’ should be

interpreted much the same as the term

‘‘contribute significantly,’’ that is, through

the same weight-of-evidence approach.

With respect to the 1-hour NAAQS, the

‘‘interfere-with-maintenance’’ prong appears

to be inapplicable. The EPA has determined

that the 1-hour NAAQS will no longer apply

to an area after EPA has determined that the

area has attained that NAAQS. Under these

circumstances, emissions from an upwind

area cannot interfere with maintenance of the

1-hour NAAQS.

With respect to the 8-hour NAAQS, the

‘‘interfere-with-maintenance’’ prong remains

important. After an area has reached

attainment of the 8-hour NAAQS, that area is

obligated to maintain that NAAQS. (See

sections 110(a)(1) and 175A.) Emissions from

sources in an upwind area may interfere with

that maintenance.

The EPA proposes to apply much the same

approach in analyzing the first component of

the ‘‘interfere-with-maintenance’’ issue,

which is identifying the downwind areas

whose maintenance of the NAAQS may

suffer interference due to upwind emissions.

The EPA has analyzed the ‘‘interfere-withmaintenance’’ issue for the 8-hour NAAQS

by examining areas whose current air quality

is monitored as attaining the 8-hour NAAQS

[or which have no current air quality

monitoring], but for which air quality

modeling shows nonattainment in the year

2007. This result is projected to occur,

notwithstanding the imposition of certain

controls required under the CAA, because of

projected increases in emissions due to

growth in emissions generating activity.

Under these circumstances, emissions from

upwind areas may interfere with the

downwind area’s ability to attain.

Ascertaining the impact on the downwind

area’s air quality of the upwind area’s

emissions aids in determining whether the

upwind emissions interfere with

maintenance
57380 Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations

28Reductions specifically required by the CAA

include, for example, the 3 percent-per-year ROP

reductions required of ozone nonattainment areas

classified as serious or higher, under section

182(c)(2)(B).

29–30 If downwind areas fail to meet their planning

obligations, they are subject to sanctions (See

Section VI, below. As EPA noted in the NPR, 62 FR

60322–23, in some instances, States in the

Northeast failed to submit all of their required SIP

revisions or other commitments under Phase 1 of

the March 2, 1995 Memorandum and as a result,

EPA initiated the sanctions process by starting

sanctions clocks. In general, those States have since

made the required Phase 1 submissions, and EPA

terminated the sanctions process by stopping the

clocks.

(62 FR 60326).

In today’s action, EPA is taking the

same positions with respect to the

interfere-with-maintenance test as

described in the NPR. Because EPA

generally interprets the ‘‘interfere-withmaintenance’’ test the same as the

‘‘contributes-significantly-tononattainment’’ test, for purposes of

convenience, in this final rule, EPA

sometimes refers to ‘‘contributessignificantly-to-nonattainment’’ to refer

to both tests.

i. Dates. In today’s action, EPA is

determining that SIP submissions

required under this rulemaking must be

submitted by September 30, 1999 (see

Section VI.A.1, Schedule for SIP

Revision).

Further, in today’s action, EPA is

requiring that SIP controls required

today must be implemented by no later

than May 1, 2003, and they must

achieve reductions computed with

reference to an overall budget amount

determined as of September 30, 2007

(see Section V, NOX Control

Implementation and Budget

Achievement Dates).

j. Downwind Areas’ Control

Obligations. Commenters have argued

that under the CAA, downwind States

must implement additional controls

before EPA may require controls in

upwind States. Commenters base this

argument in part on the provisions of

CAA section 107(a), which provides,

Each State shall have the primary

responsibility for assuring air quality within

the entire geographic area comprising such

State by submitting an implementation plan

for such State which will specify the manner

in which [NAAQS] will be achieved and

maintained within each air quality control

region in such State.

Commenters further note that

downwind States must implement

additional reductions (beyond those

specifically required by the CAA 28) as

needed to attain, under section

182(b)(1)(A)(i) and 182(c)(2)(A). The

commenters add that section 179(d)(2)

is a generally applicable provision that

limits the stringency of required

controls to what is feasible. The

commenters read these provisions

together to conclude that downwind

States must first implement all feasible

control measures in an effort to reach

attainment, and only after EPA

determines that such States have done

so but have not reached attainment may

EPA require upwind contributors to

implement controls. The commenters

further observe that some of the

downwind States in the Northeast have

not implemented all feasible SIP

measures.

The EPA disagrees with this legal

analysis. The provision in section 107(a)

that accords to States the primary

responsibility for the air quality of their

air basins, in essence provides the

underlying rationale for the requirement

of States to submit SIP revisions that

meet CAA requirements. This phrase

clarifies that the requirement of assuring

attainment does not fall, in the first

instance, on EPA. This provision does

not have implications for apportioning

responsibility between the downwind

State and upwind States for

contributions from upwind States.

Downwind States would still carry the

primary responsibility of assuring clean

air even after the upwind contributors

have revised their SIPs to meet the

requirements of section 110(a)(2)(D).

Furthermore, EPA disagrees that

section 179(d)(2) has any application to

today’s rulemaking. That provision in

essence provides a general rule that if a

nonattainment area fails to attain by its

attainment date, EPA may require the

State to implement reasonable controls

that can be ‘‘feasibly implemented.’’

This requirement is not relevant to

today’s rulemaking, which addresses the

requirements under section

110(a)(2)(D)(i)(I) that SIPs include

provisions eliminating amounts of

emissions from their sources that

contribute significantly to downwind

nonattainment.

In addition, the requirement of

downwind States to implement

reductions beyond minimum CAA

requirements if needed for attainment

does not place the burden of

implementing those reductions, in the

first instance, on the downwind States.

This requirement should be read to go

hand-in-hand with the section

110(a)(2)(D) requirement that upwind

States include SIP provisions that

prohibit their sources from emitting air

pollutants in amounts that

‘‘significantly contribute’’ to downwind

nonattainment. In today’s action, EPA is

promulgating criteria for interpreting

section 110(a)(2)(D) to take into account

downwind attainment needs.

As a practical matter, EPA has

reviewed the status of Northeast States’

efforts to comply with the requirements

of the 1990 CAA Amendments and has

found that these States have complied

with the vast majority of the SIP

submission requirements. Even so, EPA

is well aware that some of the States

have not made certain required

submissions. 29–30 However, EPA sees no

basis in section 110(a)(2)(D) to mandate

that downwind areas complete their SIP

planning and implementation before

upwind areas are required to begin that

process. Upwind areas have been

subject to the requirements of section

110(a)(2)(D)—in some form—since the

predecessor to this provision was added

in the 1977 CAA Amendments. The

EPA has determined, through air quality

modeling, that even after the downwind

States fulfill their prescribed CAA

requirements, they will have areas

expected to remain in nonattainment.

Under these circumstances, the

downwind areas continue to constitute

areas with air quality in

‘‘nonattainment’’ under section

110(a)(2)(D). As a result, upwind areas

with emissions in amounts that

‘‘significantly contribute’’ to the

nonattainment air quality downwind are

subject to control requirements whether

or not the downwind areas they affect

have met all of their planning

obligations.

k. Section 110(a)(2)(D) Caselaw. In the

NPR, EPA noted that prior to the CAA

Amendments of 1990, EPA had issued

several rulemakings under section

110(a)(2)(E), the predecessor to section

110(a)(2)(D), and section 126 that

addressed the issue of significant

contribution in the context of pollutant

transport. In those rulemakings, EPA

generally applied a multi-factor test to

determine whether the emissions from

the sources in question constituted a

signficant contribution to downwind

jurisdictions. In each instance, EPA

concluded that the emissions at issue

from the upwind sources were not

demonstrated to impact downwind air

quality in a manner that would

constitute significant contribution.

Several of these determinations resulted

in judicial challenges, but in each

instance the courts upheld the Agency’s

determination of no significant

contribution. The EPA indicated in the

NPR that the prior rulemakings and the

related court holdings, provide limited

precedents for today’s action. The EPA

noted that these decisions have limited

relevance because they involved

different facts and circumstances,

including different pollutants, different
Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations 57381

31Comprehensive Air Quality Model with

Extensions.

32The UAM–V and CAMX models are described

in the Air Quality Modeling TSD.

upwind sources, and different

downwind effects.

Several commenters asserted that

these prior rulemakings and cases are

relevant to today’s action, and compel

EPA to conclude that the emissions

from the upwind States affected by

today’s action do not contribute

significantly to downwind

nonattainment or maintenance

problems. The EPA disagrees that these

earlier determinations are controlling

and that these earlier determinations are

inconsistent with today’s action. The

EPA responds to these comments in

detail in the Response to Comment

document.

B. Alternative Interpretation of Section

110(a)(2)(D)

As discussed above, in the NPR EPA

advanced an alternative interpretation

of section 110(a)(2)(D) (62 FR 60327).

Under this alternative interpretation,

EPA would determine the level of

emissions that significantly contribute

to nonattainment downwind based on

factors relating to the entire amount of

upwind emissions from a particular

upwind State and their ambient impact

downwind. The EPA would then

determine what emissions reductions

must be required to adequately mitigate

that significant contribution based on

factors relating to cost effectiveness of

reductions and attainment needs

downwind.

The EPA continues to believe that this

alternative interpretation remains a

permissible interpretation of the statute

for the reasons described in the NPR (62

FR 60327). In any event, it should be

noted that for purposes of today’s

action, EPA finds no practical difference

between the requirements that would

result from the interpretation of section

110(a)(2)(D) adopted today and those

that would result from the alternative

interpretation described in the NPR.

That is, even under the alternative

interpretation, today’s rulemaking

would contain the same findings and

require the same SIP revisions as under

the interpretation adopted today (62 FR

60327).

C. Weight-of-Evidence Determination of

Covered States

As discussed above, EPA applied a

multi-factor approach to identify the

amounts of NOX emissions that

contribute significantly to

nonattainment. The EPA evaluated three

air quality factors for each upwind

jurisdiction (hereafter referred to as

‘‘States’’ or ‘‘upwind States’’) to

determine whether each has emissions

whose contributions to downwind

nonattainment problems are large and/

or frequent enough to be of concern.

Further, for those States whose

emissions are large and/or frequent

enough to be of concern, EPA applied

highly cost-effective controls to

determine the amount of NOx in upwind

States which significantly contributes to

nonattainment in, or interferes with

maintenance by, a downwind State. The

EPA also generally reviewed several

other considerations before drawing

final conclusions. Even though the

actual finding of significant contribution

applies only to the portion of a State’s

emissions for which EPA has identified

highly cost-effective controls, for ease of

discussion, the term ‘‘significant’’ (or

like term) is used in the discussion in

this section to characterize the

emissions of each upwind State that

make a large and/or frequent

contribution to nonattainment in

downwind States sufficient to warrant

eliminating a portion of its emissions

equivalent to what can be removed

through those controls.

The purpose of this section is to

describe the technical analyses

performed by EPA to (a) quantify the air

quality contributions from emissions in

each upwind State on both 1-hour and

8-hour nonattainment, as well as 8-hour

maintenance, in each downwind State,

and (b) determine whether these

contributions are significant.

In the proposed weight-of-evidence

approach, EPA specifically applied

several factors to each upwind State, as

discussed in Section II.A.3.c, Definition

of Significant Contribution. These

factors include:

• The overall nature of ozone

problem (i.e., ‘‘collective contribution’’);

• The extent of the downwind

nonattainment problems to which the

upwind State’s emissions are linked,

including the ambient impact of

controls required under the CAA or

otherwise implemented in the

downwind areas; and

• The ambient impact of the

emissions from the upwind State’s

sources on the downwind

nonattainment problems.

As part of the analysis of these factors,

EPA considered the findings from

OTAG’s technical analyses, as well as

the findings from a number of other

studies performed by OTAG

participants independent of OTAG. The

major findings from these analyses are

described below. This is followed by an

overview of the approach used by EPA

in the proposal for considering the

above factors to identify States that

make a significant contribution to

downwind nonattainment. The

comments and EPA’s response to

comments on EPA’s weight-of-evidence

proposal are then discussed. Following

that discussion, the results of additional

State-by-State UAM–V modeling and

State-by-State CAMX 31 source

apportionment modeling performed by

EPA in response to comments are

summarized.32 The EPA’s analysis of the

modeling results in terms of the

significance of the contributions of

upwind States to downwind

nonattainment is presented in Section

II.C.4, Confirmation of States Making a

Significant Contribution to Downwind

Nonattainment.

1. Major Findings From OTAG-Related

Technical Analyses

The major findings from the air

quality and modeling analyses by OTAG

and individual OTAG participants that

are most relevant to today’s rulemaking

are as follows:

• several different scales of transport

(i.e., intercity, intrastate, interstate, and

inter-regional) are important to the

formation of high ozone in many areas

of the East;

• emissions reductions in a given

multistate region/subregion have the

most effect on ozone in that same

region/subregion;

• emissions reductions in a given

multistate region/subregion also affect

ozone in downwind multistate regions/

subregions;

• downwind ozone benefits decrease

with distance from the source region/

subregion (i.e., farther away, less effect);

• downwind ozone benefits increase

as the size of the upwind area being

controlled increases, indicating that

there is a cumulative benefit to

extending controls over a larger area;

• downwind ozone benefits increase

as upwind emissions reductions

increase (the larger the upwind

reduction, the greater the downwind

benefits);

• a regional strategy focusing on NOX

reductions across a broad portion of the

region will help mitigate the ozone

problem in many areas of the East;

• both elevated and low-level NOX

reductions decrease ozone

concentrations regionwide;

• there are ozone benefits across the

range of controls considered by OTAG;

the greatest benefits occur with the most

emissions reductions; there was no

‘‘bright line’’ beyond which the benefits

of emissions reductions diminish

significantly;

• even with the large ozone

reductions that would occur if the most
57382 Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations

stringent controls considered by OTAG

were implemented, there may still

remain high concentrations in some

portions of the OTAG region; and a

regional NOX emissions reduction

strategy coupled with local NOX and/or

VOC reductions may be needed to

enable attainment and maintenance of

the NAAQS in this region.

The above findings provide technical

evidence that transport within portions

of the OTAG region results in large

contributions from upwind States to

ozone in downwind areas, and that a

regionwide approach to reduce NOX

emissions is an effective way to address

these interstate contributions.

2. Summary of Notice of Proposed

Rulemaking Weight-of-Evidence

Approach

The EPA relied on OTAG data to

develop the information necessary to

evaluate the weight-of-evidence factors

identified above. These data include

emissions (tons) and emission density

(tons per square mile), air quality

analyses, trajectory, wind vector, and

‘‘ozone cloud’’ analyses, and

subregional zero-out modeling. In brief,

EPA’s proposed approach was as

follows:

• the OTAG transport distance scale

was applied to identify, based on the

meteorological potential for transport,

which States may contribute to ozone in

downwind States;

• the results of the OTAG subregional

modeling runs (described below) were

used to quantify the extent to which

each subregion contributes to

downwind nonattainment for the 1-hour

and/or 8-hour NAAQS;

• the OTAG 2007 Base Case NOX

emissions and emissions density were

used to identify States which emit large

amounts of NOX and/or have a high

density of NOX emissions compared to

other States in the OTAG region and,

therefore, have NOX emissions which

may be great enough to contribute to

downwind nonattainment; and the

OTAG 2007 Base Case NOX emissions

were also used to translate the findings

from the subregional modeling to a

State-by-State basis.

a. Quantification of Contributions. As

part of OTAG’s assessment of transport,

a series of model runs were performed

to examine the impacts of emissions

from each of 12 multistate subregions on

ozone in downwind areas. The locations

of these subregions are shown in Figure

II–1.

In each subregional model run, all

manmade emissions were removed from

one upwind subregion and the model

was run for the OTAG July 1988 and

1995 episodes. The ‘‘parts per billion

(ppb)’’ differences in ozone between

each subregional zero-out run compared

to the corresponding 2007 Base Case run

were used to quantify the air quality

impacts of the subregion on

nonattainment downwind.

In the proposed NOX SIP call, EPA

considered areas as ‘‘nonattainment’’ if

air quality monitoring indicates that the

area is currently measuring

nonattainment and if air quality

modeling indicates future

nonattainment, taking into account CAA

control requirements and growth. In this

regard, areas were considered

nonattainment for the 1-hour NAAQS if
Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations 57383

33 Data for 1994–1996 were used because these

were the most recent quality-assured data available

at the time the analysis was performed.

34 In response to comments, EPA has reexamined

the method for relating 8-hour model predictions

during the OTAG episodes to the form of the 8-hour

NAAQS. This is discussed further in Section

II.C.2.c, Comments and Responses on the Proposed

Weight of Evidence Approach to Significant

Contribution.

they had 1994–1996 33 monitoring data

indicating measured 1-hour violations

and 2007 Base Case 1-hour predictions

>=125 ppb. Areas were considered to be

nonattainment for the 8-hour NAAQS if

they had 1994–1996 monitoring data

indicating measured 8-hour violations

and 2007 Base Case 8-hour predictions

>=85 ppb. The inconsistency between

the form of the 8-hour NAAQS, which

considers 3 years of data for

determining the average of the fourthhighest 8-hour daily maximum

concentration at a monitor, and the

limited predictions available from the

OTAG episodes introduced a

complication to the analysis of 8-hour

contributions. It was not possible to use

the model predictions in a way that

explicitly matched the form of the 8-

hour NAAQS. Instead, an analysis of

seasonal and episodic ozone

measurements was performed in an

attempt to link 8-hour measured

concentrations during the OTAG

episodes to the form of the 8-hour

NAAQS, as closely as possible. The

results of that analysis indicated that the

3-episode average of the second highest

8-hour ozone concentrations measured

during the OTAG 1991, 1993, and 1995

episodes corresponded best, overall, to

the 3-year average of the fourth highest

8-hour daily ambient data. However,

since OTAG subregional modeling was

only available for the 1988 and 1995

episodes, EPA used the concentrations

during these two episodes in calculating

average second high 8-hour

concentrations.34

b. Evaluation of 1-Hour and 8-Hour

Contributions. In the proposal, EPA

summarized the ‘‘ppb’’ contributions to

downwind nonattainment from each

subregion in terms of both the frequency

and the magnitude of the downwind

impacts over specific concentration

ranges (e.g., 2 to 5 ppb, 5 to 10 ppb, 10

to 15 ppb, etc.). The results indicate

that, in general, large contributions to

downwind nonattainment occur on

numerous occasions. Although the level

of downwind contribution varies from

subregion to subregion, a consistent

pattern is apparent for both 1-hour

nonattainment and 8-hour

nonattainment. Specifically, the results

of the subregional modeling indicate

that emissions from States in subregions

1 through 9 produce large 1-hour and 8-

hour contributions downwind in terms

of the magnitude and frequency,

including geographic extent, of the

downwind impacts. In addition,

nonattainment areas within many States

in the OTAG region receive large and/

or frequent contributions from

emissions in these subregions. The EPA

proposed to find that most of the States

whose emissions are wholly or partially

contained within one or more of these

subregions (i.e., Alabama, Connecticut,

Delaware, Georgia, Illinois, Indiana,

Kentucky, Maryland, Michigan,

Missouri, New Jersey, New York, North

Carolina, Ohio, Pennsylvania, South

Carolina, Tennessee, Virginia, West

Virginia, and Wisconsin, as well as the

District of Columbia) are making a

significant contribution to downwind

nonattainment. In addition to the

ambient impact demonstrated by the

subregional modeling, this proposed

finding was based on a determination

that:

• OTAG strategy modeling and nonOTAG modeling indicate that NOX

emissions reductions across these States

would produce large reductions in 1-

hour and 8-hour ozone concentrations

across broad portions of the region

including 1-hour and 8-hour

nonattainment areas;

• these States are upwind from

nonattainment areas within the 1- to 2-

day distance scale of transport;

• these States form a contiguous area

of manmade emissions covering most of

the core portion of the OTAG region;

• 11 of the States that are wholly

within subregions 1 through 9 have a

relatively high level of NOX emissions

from sources in their States; these States

are ranked in the top 50 percent of all

States in the region in terms of total

NOX emissions and/or have NOX

emissions exceeding 1000 tons per day;

• States wholly within subregions 1

through 9 with lesser emissions have a

relatively high density of NOX

emissions;

• for the seven States that are only

partially contained in one of subregions

1 through 9, the State total NOX

emissions, as well as each State’s

contribution to NOX emissions in the

subregions in which they are located,

indicate that six of the States each have:

NOX emissions that are more than 10

percent of the total NOX emissions in

one of these subregions, NOX emissions

in the top 50 percent among all States,

and/or a majority of its NOX emissions

within one of these subregions.

For the New England States that were

not included in any of the OTAG zeroout subregions, EPA found that two of

these States (i.e., Massachusetts and

Rhode Island) have a high density of

NOX emissions. Also, the trajectory and

wind vector analyses indicated that

these States are immediately upwind of

nonattainment areas in other States.

For the nine States in the OTAG

region which are wholly within

subregions 10, 11, and 12 (i.e., Florida,

Kansas, Louisiana, Minnesota,

Nebraska, North Dakota, Oklahoma,

South Dakota, and Texas), and for

Arkansas, Iowa, and Mississippi, EPA

proposed that emissions from each of

these States should be considered not to

significantly contribute to downwind

nonattainment. These States are further

discussed below in Section II.C.5, States

Not Covered by this Rulemaking.

c. Comments and Responses on

Proposed Weight-of-Evidence Approach

to Significant Contribution. The EPA

received a number of comments on

various elements of the proposed

weight-of-evidence approach. In

addition, EPA received new modeling

and analyses performed by commenters

which address the issue of significant

contribution. The following is a

summary of the major comments

received by EPA and the responses to

these comments. Additional comments

and EPA’s response to these comments

are provided in the Response to

Comment document.

Comment: Some commenters stated

that it was inappropriate to use a

weight-of-evidence approach to

determine the significance of upwind

emissions on downwind nonattainment.

Rather, it was argued that EPA should

use a specific ‘‘bright line’’ criterion.

Other commenters supported the

weight-of-evidence approach.

Response: The magnitude and

frequency of contributions from an

upwind State to downwind

nonattainment depend on the extent of

the nonattainment problem in the

downwind area, the emissions in the

downwind area, the emissions in the

upwind State, the distance between the

upwind State and the downwind area,

and weather conditions (i.e., winds and

temperatures which favor ozone

formation and transport). Because these

factors vary in a complex way across the

OTAG region, it is not possible to

develop a single bright line test for

significance that will be applicable and

appropriate for all potential upwindState-to-downwind-area linkages.

Therefore, EPA believes that it is more

appropriate to use a weight-of-evidence

approach to account for all of these

factors than establishing a bright line

criterion.

Comment: Some commented that EPA

should not use the trajectory, wind

vector, and ‘‘ozone cloud’’ analyses as a
57384 Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations

basis for determining significant

contribution because these techniques

indicate air movement and do not

account for ozone formation and

depletion due to photochemical

reactions and other processes. Other

commenters argued in favor of using

this information as means of linking

upwind States with downwind

nonattainment.

Response: The EPA agrees that

information from such techniques

should not be used as the sole basis for

finding that certain upwind States

significantly contribute to

nonattainment in specific downwind

States. However, EPA believes that it is

important to consider the ‘‘movement’’

of ozone and/or precursors as part of the

air quality evaluation of contributions

from upwind States. This factor is

incorporated into the air quality models

used by EPA for this rulemaking. The

inclusion of this information, in

conjunction with numerous other air

quality factors in the models, provides

for a more technically robust analysis

than can be provided by the trajectory,

ozone cloud, and wind vector analyses

alone.

Comment: A number of commenters

stated that CAA section 110(a)(2)(D)

requires a State-by-State demonstration

that emissions within an upwind State

make a significant contribution to

nonattainment in another State and

thus, EPA’s proposed approach of using

subregional (i.e., multistate) modeling,

together with each upwind State’s NOX

emissions, to establish these linkages is

legally flawed. These commenters

argued that section 110(a)(2)(D) requires

‘‘each implementation plan submitted

by a State’’ to contain provisions that

prohibit any source or other type of

emissions activity ‘‘within the State’’

from emitting air pollutants in amounts

that contribute significantly to a

downwind nonattainment problem. The

commenters concluded that these

provisions require, as a matter of

technical procedure, that EPA must base

its determination that emissions from a

particular State significantly contribute

to nonattainment downwind on a

technical analysis of that particular

State’s emissions. According to the

commenters, section 110(a)(2)(D) by its

terms, prohibits EPA from making that

technical determination by examining

the impact of emissions from a group of

States on a downwind nonattainment

problem, and then extrapolating from

that information to determine whether

emissions from each State within that

group should be considered to make a

significant contribution.

As a technical matter, these

commenters argue that if emissions from

more than one State are lumped together

in assessing the contribution to a

downwind State, there is no way to

determine the amount of emissions in

each contributing State that must be

reduced. The commenters argue that the

only way to establish specific upwind

State to downwind State linkages is

through air quality modeling on a Stateby-State basis. Further, the commenters

contend that once an area beyond a

particular State’s boundaries is

modeled, there is no way of knowing

how much farther upwind to go in terms

of defining a source area. In order to

address these issues, many commenters

stated that EPA must do State-by-State

zero-out UAM–V modeling and/or Stateby-State source apportionment

modeling using the CAMx model to

determine downwind contributions

from upwind States.

Response: On the legal issue, EPA

disagrees that the above-referenced

provisions of section 110(a)(2)(D), by

their terms, mandate the technical

procedure for EPA to make the

determination of significant

contribution. These provisions simply

indicate that EPA must make that

determination on a SIP-by-SIP basis,

that is, for EPA to issue a SIP call with

respect to a particular State, EPA must

determine that the provisions of that SIP

fail to adequately control emissions

from sources within the State. However,

these provisions do not mandate any

particular technical procedure for

making that determination. As a result,

EPA may employ any technical

procedure that is sufficiently accurate.

As discussed below, EPA believes that

its subregional approach is sufficiently

accurate to justify the SIP call. However,

in response to this and other comments,

EPA did conduct State-by-State

modeling. The results of this modeling,

as discussed below, confirm the results

of the subregional modeling.

On the technical issue, EPA used the

subregional modeling as part of the

proposed approach because OTAG had

developed and relied on this modeling

as part of its analysis to quantify the

impacts of manmade emissions in

upwind areas on ozone in downwind

areas. In addition, in conjunction with

other information, EPA believes that it

is possible to make rational

extrapolations from the subregional

results in order to draw conclusions as

to the contribution of individual States.

The EPA believes that it is credible to

use NOx emissions in each State, along

with the subregional modeling results,

in the determination of significance in

view of the results of OTAG modeling

which indicate that, in addition to local

emissions, the level of ozone in a

downwind State is directly related to

the magnitude of NOx emissions in

upwind areas and the proximity of the

upwind area to the downwind State. A

more detailed discussion of the

technical validity of the subregional

modeling is contained in the Response

to Comment Document.

The EPA recognizes that State-byState modeling would provide some

additional precision to the magnitude

and frequency of individual State-toState contributions. In response to the

recommendations for additional

modeling, EPA performed both State-byState UAM–V zero-out modeling and

State-by-State CAMx source

apportionment modeling for many of

the upwind States in the OTAG region

which were proposed as significant

contributors. The EPA’s analysis of the

contributions to downwind

nonattainment using the State-by-State

modeling confirms the overall finding,

based on the proposed subregional

modeling, that the 23 jurisdictions

identified in the proposal significantly

contribute to nonattainment in

downwind States. Specifically, the

subregional modeling indicates that

manmade emissions from sources in

subregions 1 through 9 make large and/

or frequent contributions to 1-hour and

8-hour nonattainment in specific

downwind States. The EPA’s analysis of

the State-by-State modeling

demonstrates that each of the 23

upwind jurisdictions identified through

subregional modeling significantly

contribute to nonattainment in specific

downwind States. In addition, the

results of the State-by-State modeling

show that the specific upwind-State-todownwind-nonattainment linkages

indicated by the subregional modeling

are confirmed overall by the State-byState modeling. The State-by-State

modeling analyses are summarized

below and more fully documented in

the Air Quality Modeling TSD.

Comment: The EPA received

comments that zero-out modeling

introduces sharp spatial changes in

emissions and pollutants along the

edges of the zero-out area. The

commenters contend that this is not

credible and provides an incorrect

assessment of transport.

Response: The EPA disagrees with

this comment, as discussed in the

Response to Comments document. Also,

as indicated above, in response to other

comments, EPA has performed CAMx

source apportionment modeling which

does not use a zero-out technique for

quantifying ozone contributions from

upwind States. In general, EPA has

found that the source apportionment

technique and zero-out modeling
Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations 57385

35For the purposes of discussion in this Section,

these values are referred to as ‘‘design’’ values.

provide consistent information on the

relative contribution of upwind States to

downwind nonattainment. In cases

where the two techniques do not

provide consistent results, the source

apportionment technique tends to

indicate larger contributions than the

zero-out modeling. The differences

between these two modeling techniques

are described further in the Air Quality

Modeling TSD.

Comment: Some comments referenced

a study which analyzed the ‘‘noise’’

(i.e., uncertainty) in the UAM–V

modeling system. This study purports to

show that the contributions from some

States EPA proposed as significant are

within the ‘‘noise’’ of the model.

Response: This study focuses on

model uncertainty by varying many, but

not all, inputs to the model. The study

does not contend that the inputs

selected by OTAG are incorrect, but

rather that there may be other plausible

values for these inputs. The results

indicate that there is a range of

uncertainty in predicted ozone

associated with the range of possible

values for the particular inputs studied

by the commenter. The study does not

indicate that there is any bias in the

model’s predictions (i.e., there is no

indication that the predictions are too

high or too low). The specific values for

the inputs being used by EPA in its air

quality modeling are the same values

that were used by OTAG. These values

were selected by the OTAG Regional

and Urban Scale Modeling Work Group,

which included experts in air quality

modeling from the public and private

sector, in conjunction with the model’s

developers, Systems Application

International. The predictions from

OTAG’s model runs using these same

input values were evaluated against

ambient measurements and found by

OTAG to provide acceptable results.

The EPA continues to believe that the

specific inputs selected by OTAG are

technically sound and the modeling

results are credible. A further discussion

of EPA’s response to this comment is in

the Response to Comments document.

Comment: Several commenters stated

that emissions from large point sources

of NOx in specific States do not

contribute significantly to downwind

nonattainment.

Response: As discussed in Section

II.A.3.c, Definition of Significant

Contribution, under EPA’s collective

contribution approach, if emissions in

the aggregate from a particular

geographic region or State are found to

contribute significantly to

nonattainment downwind, then the

emissions in that region or State are

considered to be significant contributors

to that nonattainment problem.

Moreover, EPA treats emissions as

‘‘contributing significantly’’ only to the

extent they may be eliminated through

highly cost-effective reductions. Thus, if

all emissions from a State, when

considered in the aggregate, are found to

contribute significantly to

nonattainment downwind, and if there

are highly cost-effective controls for

NOx emissions from sources in the

upwind State, then the amount of NOx

emissions from these sources that can be

eliminated with such controls are

considered to be making a significant

contribution. The amount of emissions

determined through this approach to

make a significant contribution may be

relatively small, compared to the

upwind State’s entire inventory; and the

ambient impact downwind of

eliminating that amount may be

relatively small as well. However, this

small impact does not mean that the

emissions themselves are not significant

insofar as their contribution to

nonattainment downwind. Further, as

discussed in Section IV, Air Quality

Assessment, when the amount of

emissions required to be eliminated

from upwind States are combined and

modeled collectively, their ambient

impact downwind is larger.

Comment: One commenter provided a

recommendation for dealing with the

concern that the spatial resolution of

meteorological inputs to the air quality

model may be too coarse to require that

predicted exceedences correspond

exactly with a county violating the

NAAQS. The commenter’s

recommendations were to base the

selection of 1-hour nonattainment

receptors on model predicted

exceedences in either (a) all counties

within the metropolitan statistical area

containing the nonattainment area or (b)

all counties comprising the designated

1-hour nonattainment area.

Response: The EPA believes that the

appropriate way to address this issue is

to use all counties comprising the

designated 1-hour nonattainment area.

That is, all counties in a designated 1-

hour nonattainment area should be

considered as possible nonattainment

receptors for the purposes of evaluating

contributions to nonattainment under

the 1-hour NAAQS. The EPA recognizes

that not all counties within a designated

nonattainment area have monitors, and

that some counties may have monitors

that indicate attainment in that county.

Even so, EPA recognizes that under the

1-hour NAAQS, nonattainment

boundaries are generally used to

describe an area with the nonattainment

problem. Thus, EPA believes that this

geographic vicinity offers the best

indication of an area that may be

expected to have nonattainment air

quality somewhere within its

boundaries. The EPA believes that it is

appropriate to include all counties in

the designated nonattainment area

because the entire nonattainment area is

responsible for meeting the 1-hour

NAAQS, even if only one monitor

measures nonattainment at any one

time. As noted elsewhere, EPA predicts

that many 1-hour nonattainment areas

that currently monitor nonattainment

somewhere within the area will remain

in nonattainment in 2007, in some cases

because of predicted violations in

counties that currently monitor

attainment. The EPA believes that the

entire area should be considered to be

in nonattainment until all monitors in

the area indicate attainment of the

NAAQS. Thus, in today’s rulemaking,

EPA used the designated 1-hour

nonattainment area in selecting the

receptors to be used to evaluate impacts

on downwind nonattainment problems.

Comment: Several commenters

questioned the validity of EPA’s

approach of using the 3-episode average

of the second highest 8-hour daily

maximum concentration to represent

the form of the 8-hour NAAQS (i.e., the

3-year average of the fourth highest 8-

hour daily maximum values at a

monitor 35). Commenters expressed the

concern that the average second high

may not be representative for all areas

across the OTAG domain. However,

none of the commenters provided any

suggested alternatives to EPA’s

approach.

Response: The analysis performed by

EPA to establish a relationship between

the air quality during the OTAG

episodes and the form of the 8-hour

NAAQS was based upon an analysis of

3 years of monitoring data compared to

monitoring data during the OTAG

episodes. In response to comments, EPA

performed an analysis to determine how

the predicted average second high 8-

hour values, as well as several

alternative 8-hour values, compared to

ambient 8-hour design values, based on

1994 to 1996 measured data. Based on

this analysis, EPA determined that,

overall, the model-predicted average

second high values underestimate the

corresponding ambient design values for

those counties in the OTAG domain

with 1994–1996 ambient values >=85

ppb. In addition to the average second

high, EPA also compared six other

measures of 8-hour model predictions to

ambient design values. The six other

measures include the highest, second
57386 Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations

36Similarly, the EPA is also using 1-hour model

predictions >=125 ppb as an indicator that areas

currently designated nonattainment for the 1-hour

NAAQS will continue to be nonattainment for the

1-hour NAAQS in 2007.

37As explained elsewhere, for the 1-hour

standard, EPA based its determination as to the

boundaries of the area with air quality violating the

NAAQS on the boundaries of the area designated

as nonattainment.

38 Indeed, the modeling relied on in today’s action

indicates that many downwind nonattainment areas

carry a residual nonattainment problem even after

implementation of regional reductions by all the

States affected by today’s action. Although not

essential to EPA’s conclusions, the presence of this

nonattainment problem even after implementation

of regional controls, based on the modeling used in

today’s rulemaking, indicates that even further

reductions, regionally or locally, would be needed

to assure attainment in those downwind areas.

highest, third highest, and fourth

highest ozone predictions across the

July 1991, 1993, and 1995 episodes; the

3-episode average of the highest

concentrations; and the 3-episode

average of the highest, second highest,

and third highest concentrations. The

EPA also developed the same measures

using model predictions from all 4

episodes for comparison to the ambient

design values. The results indicate that

none of the alternative measures

provides a universal best match to

ambient 8-hour design values in all

States. Each of the indicators

overestimates values in some areas and

underestimates values in other areas to

a varying extent. Furthermore, the best

representation of 8-hour design values

using predictions from the OTAG

episodes varies from State to State.

Given that the predicted average second

high underestimates ambient 8-hour

design values and that none of the other

8-hour indicators examined by EPA

provides a ‘‘best’’ match to ambient

values in all cases, EPA has decided to

analyze the contributions to 8-hour

nonattainment problems using all 8-

hour predictions >=85 ppb. The EPA

believes that this approach is

appropriate given that EPA is using

modeling results for the 8-hour NAAQS

merely as an indicator of the likelihood

that areas that currently monitor

violations of the 8-hour NAAQS will

continue to be nonattainment for the 8-

hour NAAQS and/or have 8-hour

maintenance problems in 2007.36 Thus,

the air quality analysis of 8-hour

contributions, described below, focuses

on all 8-hour values >=85 ppb.

Comment: Several commenters

submitted new State-by-State zero-out

modeling using UAM–V and CAMx

source apportionment modeling

purporting to show that contributions

from particular upwind States are

insignificant.

Response: The EPA reviewed the

commenters’ modeling to determine and

assess (a) the technical aspects of the

models that were applied; (b) the types

of episodes modeled; (c) the methods for

aggregating, analyzing, and presenting

the results; (d) the completeness and

applicability of the information

provided; and (e) whether the technical

evidence supports the arguments made

by the commenters. Overall, the

modeling submitted by commenters is

viewed by EPA as generally technically

credible, although not complete in all

cases. The EPA’s ability to fully evaluate

and utilize the modeling submitted by

commenters was hampered in some

cases because only limited information

on the results was provided. For

example, a commenter may have

provided results for only 1 or 2 days in

an episode, or for only one of several

episodes with no information presented

on the results for the remaining days or

episodes that were modeled. As another

example, results were presented for only

the peak ozone day in an episode while

greater contributions may have been

predicted on other high ozone days of

the episode. For some of the modeling,

the information was only presented in

graphical form which made the results

difficult to evaluate in a quantitative

way. Also, in some cases the model

predictions were only presented as

episode composite values without

information on peak contributions. The

EPA’s full assessment of the modeling

submitted by commenters is provided in

the Response to Comments document.

In light of the absence of complete

information in the modeling provided

by commenters and other comments

calling for State-by-State analyses, EPA

decided to perform additional air

quality modeling of the type submitted

by commenters in order to consider all

of the data resulting from such model

runs. The EPA modeling includes Stateby-State zero-out modeling using UAM–

V and State-by-State CAMx source

apportionment modeling.

EPA conducted further analysis of

other factors included in the multifactor approach for significant

contribution. The results of EPA’s

consideration of these factors and EPA’s

modeling are described next.

3. Analysis of State-specific Air Quality

Factors

a. Overall Nature of Ozone Problem

(‘‘Collective Contribution’’). As

described above, EPA believes that each

ozone nonattainment problem at issue

in today’s rulemaking is the result of

emissions from numerous sources over

a broad geographic area. The

contribution from sources in an upwind

State must be evaluated in this context.

This ‘‘collective contribution’’ nature of

the ozone problem supports the

proposition that the solution to the

problem lies in a range of controls

covering sources in a broad area,

including upwind sources that cause a

substantial portion of the ozone

problem. This upwind share is typically

caused by NOx emissions from sources

in numerous States. States adjacent to

the State with the nonattainment

problem generally make the largest

contribution, but States further upwind,

collectively, make a contribution that

constitutes a large percentage in the

context of the overall problem. As an

example to illustrate the overall nature

of the ozone problem, EPA discusses

below the ozone problem in the New

York City nonattainment area.

b. Extent of Downwind

Nonattainment Problems. For each

downwind area to which an upwind

State may be linked, EPA also examined

the extent of the downwind

nonattainment problem, including the

air quality impacts of controls required

in downwind areas under the CAA, as

well as of controls required or

implemented on a national basis. As

indicated elsewhere, EPA determined

that a downwind area should be

considered ‘‘nonattainment’’ for

purposes of section 110(a)(2)(D)(i)(I)

under the 1-hour NAAQS if the area

currently (as of the 1994–96 time

period) has nonattainment air quality 37

and if the area is modeled to have

nonattainment air quality in the year

2007, after implementation of all

measures specifically required of the

area under the CAA as well as

implementation of Federal measures

required or expected to be implemented

by that date. The EPA determined that

each such downwind area had a

residual nonattainment problem even

after implementation of all these control

measures. The presence of residual

nonattainment is a factor that supports

the need to reduce emissions from

upwind sources to allow further

progress towards attainment.38 As an

example, the residual nonattainment for

the New York City area is discussed in

more detail below.
Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations 57387

39For ease of discussion, EPA is using the term

‘‘UAM–V’’ to refer to the UAM–V State-by-State

zero-out modeling and the term ‘‘CAMx’’ to refer to

the CAMx source apportionment modeling.

40For ease of discussion in this Section, the 1-

hour nonattainment areas and the set of

nonattainment receptors pooled over an entire State

are referred to as downwind areas.

41High measured ozone concentrations in

portions of Illinois, Indiana, Michigan, and

Wisconsin near the shoreline of Lake Michigan are

often associated with weather conditions which

cause ozone precursor pollutants to be blown

offshore over the lake during the morning, where

they can form high ozone concentrations which

then return onshore during ‘‘lake breeze’’ wind

flows in the afternoon. Because the size of the grid

cells used in the OTAG modeling is relatively large

compared to the spatial scale of the lake breeze, the

high ozone concentrations predicted over the lake

may not be blown back onshore in the model. Since

high concentrations over the lake do, in reality,

impact air quality along the shoreline of one or

more of these States, the EPA believes that it is

appropriate to use predicted contributions to ozone

over Lake Michigan as a surrogate for contributions

to any one of the surrounding States (i.e., Illinois,

Indiana, Michigan, and Wisconsin).

c. Air Quality Impacts of Upwind

Emissions on Downwind

Nonattainment. As indicated above, in

response to comments, additional air

quality modeling was performed by EPA

to confirm the proposed approach

which relied on subregional modeling to

quantify the impacts of emissions from

upwind States on nonattainment in

downwind areas. The additional

modeling consisted of State-by-State

zero-out modeling using UAM–V and

State-by-State source apportionment

modeling using the CAMx

Anthropogenic Precursor Culpability

Assessment (APCA) technique.39 A

description of these models is contained

in the Air Quality Modeling TSD. Both

models are currently being used by the

scientific and regulatory community for

air quality assessments. The EPA is not

aware of any information that would

indicate that either model provides

more credible predictions than the

other. Each modeling technique (i.e.,

zero-out and source apportionment)

provides a different technical approach

to quantifying the downwind impact of

emissions in upwind States. The zeroout modeling analysis provides an

estimate of downwind impacts by

comparing the model predictions from a

Base Case run to the predictions from a

run in which the Base Case manmade

emissions are removed from a specific

State. In contrast, the source

apportionment modeling quantifies

downwind impacts by tracking

formation, chemical transformation,

depletion, and transport of ozone

formed from emissions in an upwind

source area and the impacts that ozone

has on nonattainment in downwind

areas. The EPA ran both models for all

four OTAG episodes (i.e., July 1–11,

1988; July 13–21, 1991; July 20–30,

1993; and July 7–18, 1995) using the

2007 SIP Call Base Case emissions. The

development of emissions for this Base

Case scenario are described in Section

IV, Air Quality Assessment.

The EPA selected several metrics in

order to evaluate the downwind

contributions from emissions in upwind

States. The metrics were designed to

provide information on the three

fundamental factors for evaluating

whether emissions in an upwind State

make large and/or frequent

contributions to downwind

nonattainment. These factors are (a) the

magnitude of the contribution, (b) the

frequency of the contribution, and (c)

the relative amount of the contribution.

The magnitude of contribution factor

refers to the actual amount of ‘‘ppbs’’ of

ozone contributed by emissions in the

upwind State to nonattainment in the

downwind area. The frequency of the

contribution refers to how often the

contributions occur and how extensive

the contributions are in terms of the

number of grids in the downwind area

that are affected by emissions in the

upwind State. The relative amount of

the contribution is used to compare the

total ‘‘ppb’’ contributed by the upwind

State to the total ‘‘ppb’’ of

nonattainment in the downwind area.

As indicated above, two modeling

techniques (i.e., UAM–V zero-out and

CAMx source apportionment) were used

for the State-by-State evaluation of

contributions. The EPA developed

metrics for both modeling techniques

for each of the three factors. However,

because of the differences between the

two techniques, some of the metrics

used for the UAM–V modeling and the

CAMx modeling are different. The

specific UAM–V and CAMx metrics and

how they relate to the three factors used

for the evaluation of contributions are

described below.

The EPA examined the contributions

from upwind States to downwind

nonattainment for several types of

nonattainment receptors. Nonattainment

receptors for the 1-hour analysis include

those grid cells that (a) are associated

with counties designated as

nonattainment for the 1-hour NAAQS

and (b) have 1-hour Base Case model

predictions >=125 ppb. These grid cells

are referred to as ‘‘designated plus

modeled’’ nonattainment receptors.

Using these receptors, the metrics were

calculated for each 1-hour

nonattainment area as well as for each

State. To calculate the metrics by State,

all of the 1-hour nonattainment

receptors in that State were pooled

together.40 Table II–1 lists the 1-hour

nonattainment areas that were

considered in this analysis, along with

the State(s) in which the nonattainment

area is located. In addition to the areas

listed in Table II–1, EPA also evaluated

the contributions of upwind States to

ozone concentrations over Lake

Michigan because modeled air quality

over the lake can be indicative, under

certain weather conditions, of air

quality in portions of the States

surrounding the lake.41

TABLE II–1.—1-HOUR NONATTAINMENT AREAS EVALUATED

Nonattainment area State(s)

Atlanta ................................................................. Georgia.

Baltimore ............................................................. Maryland.

Birmingham ......................................................... Alabama.

Boston/Portsmouth 1 ........................................... Massachusetts, New Hampshire.

Chicago/Milwaukee 2 ........................................... Illinois, Indiana, Wisconsin.

Cincinnati ............................................................ Kentucky, Ohio.

Greater Connecticut ............................................ Connecticut.

Louisville ............................................................. Indiana, Kentucky.

Memphis .............................................................. Mississippi, Tennessee.

New York City ..................................................... Connecticut, New Jersey, New York.

Philadelphia ......................................................... Delaware, Maryland, New Jersey, Pennsylvania.

Pittsburgh ............................................................ Pennsylvania.

Portland ............................................................... Maine.

Rhode Island ....................................................... Rhode Island.

Southwestern Michigan 3 ..................................... Michigan.
57388 Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations

42Model predictions from the first few days of

each episode are considered ‘‘ramp-up’’ days and

were excluded from the analysis, following the

procedures adopted by OTAG. The ramp-up days

include the first 3 days of the July 1988, 1991, and

1995 episodes and the first 2 days of the July 1993

episode.

TABLE II–1.—1-HOUR NONATTAINMENT AREAS EVALUATED—Continued

Nonattainment area State(s)

St. Louis .............................................................. Illinois, Missouri.

Washington, DC .................................................. District of Columbia, Maryland, Virginia.

Western Massachusetts ...................................... Massachusetts.

1For the purposes of this analysis EPA has combined the Greater Boston nonattainment area which includes portions of Massachusetts and

New Hampshire, with the Portsmouth, New Hampshire nonattainment area into a single downwind nonattainment receptor area. 2For the purposes of this analysis EPA has combined the 1-hour nonattainment counties that are along the shoreline of Lake Michigan in the

States of Illinois, Indiana, and Wisconsin into a single downwind nonattainment receptor area. 3For the purposes of this analysis EPA has combined the 1-hour nonattainment counties that are along the shoreline of Lake Michigan in the

State of Michigan into a single downwind nonattainment receptor area.

For the 8-hour analysis,

nonattainment receptors are those grid

cells that (a) are associated with

counties currently violating the 8-hour

NAAQS (based on 1994–1996 data) and

(b) have 8-hour Base Case model

predictions >=85 ppb. These grid cells

are referred to as ‘‘violating plus

modeled’’ nonattainment receptors. The

metrics for the 8-hour contribution

analyses were calculated on a State-byState basis by pooling together the

‘‘violating plus modeled’’ receptors in a

State.

(1) UAM–V State-by-State Modeling.

In the UAM–V zero-out model runs all

manmade emissions in a given upwind

State were removed from the Base Case

scenario. Each zero-out scenario was

run for all 4 episodes and the ozone

predictions in downwind States were

then compared to those from the Base

Case run in order to quantify the

downwind impacts of emissions from

the upwind State (i.e., the State in

which the manmade emissions were

removed). The EPA performed zero-out

runs for the following set of States:

• Alabama, Georgia, Illinois, Indiana,

Kentucky, Massachusetts, Michigan,

Missouri, North Carolina, Ohio, South

Carolina, Tennessee, Virginia, West

Virginia, and Wisconsin.

Zero-out modeling for Massachusetts

was performed because this State was

the only State in the Northeast with

relatively large NOX emissions that was

not included in any of the OTAG

subregional modeling. The other States

listed above were selected for zero-out

modeling in order to respond to

comments that emissions in all or

portions of each of these States do not

contribute significantly to downwind

nonattainment.

The EPA analyzed the modelpredicted ozone concentrations from the

zero-out runs using the four metrics

described below. The results for these

metrics are too voluminous to include

in the notice in their entirety. The full

set of results is contained in the Air

Quality Modeling TSD. Each metric was

calculated using 1-hour daily maximum

concentrations >=125 ppb as well as 8-

hour daily maximum concentrations

>=85 ppb. Model predictions from all 4

episodes were used for calculating the

metrics.42

UAM–V Metric 1: Exceedences. This

metric is the total number of predicted

concentrations exceeding the NAAQS

(i.e. 1-hour values >=125 ppb and 8-

hour values >=85 ppb) within the

downwind area. In calculating this

metric, EPA summed the number of

occurrences of values above the

applicable standard (i.e., 1-hour or 8-

hour) for all nonattainment receptors

within the downwind area. For

example, in Downwind Area #1 there

are five 1-hour ‘‘designated plus

modeled’’ nonattainment receptors. For

this downwind area, the Base Case

value for Metric 1 is calculated by first

counting the number of days, across all

four episodes, that had 1-hour daily

maximum values >=125 ppb at each of

the five receptors. The result is the total

number of exceedences at each receptor

over all days in all four episodes. The

total number of exceedences at each

receptor is then summed across all five

receptors to produce the total number of

exceedences in Downwind Area #1,

which is the value for Metric 1 for this

area.

UAM–V Metric 2: Ozone Reduced—

ppb. This metric shows the magnitude

and frequency of the ‘‘ppb’’ impacts

from each upwind State on ozone

concentrations in each downwind area.

These impacts are quantified by

calculating the difference in ozone

concentrations between the zero-out run

and the Base Case. The results are then

tabulated in terms of the number of

‘‘impacts’’ within six concentration

ranges: >=2 to 5 ppb, >=5 to 10, >=10

to 15, >=15 to 20, >=20 to 25, and >=25

ppb. The impacts for 1-hour daily

maximum values and 8-hour daily

maximum values are determined by

tallying the total ‘‘number of days and

grid cells’’ >=125 ppb or >=85 ppb that

receive contributions within the

concentration ranges. In the analysis of

contributions, as described below, the

data from Metric 2 are used in

conjunction with Metric 1 to determine

the percent of the exceedences in the

downwind area that receive

contributions of >=2 ppb, >= 5 ppb,

>=10, ppb, etc. The maximum ‘‘ppb’’

impact within the downwind area is

also calculated.

UAM–V Metric 3: Total ppb Reduced.

This metric quantifies the total ppb

contributed in the downwind area from

an upwind State, not including that

portion of the contribution that occurs

below the level of the NAAQS. For 1-

hour concentrations, Metric 3 is

calculated by taking the difference

between the Base Case predictions in

each nonattainment receptor and either

(a) the corresponding value in the zeroout run, or (b) 125 ppb, whichever is

greater (i.e., 125 ppb or the prediction

in the zero-out run). The Base Case vs.

zero-out differences are summed over

all days and across all nonattainment

receptors in the downwind area. The

calculation of this metric is illustrated

by the following example. If the Base

Case 1-hour daily maximum ozone

prediction is 150 ppb and the

corresponding value from the zero-out

run is 130 ppb, then the difference used

in this metric is 20 ppb. However, if the

value from the zero-out run is 115 ppb,

then the difference used in this metric

is 25 ppb (i.e., 150 ppb–125 ppb,

because 115 ppb is less than 125 ppb).

For analyzing the contributions using

Metric 3, the values of this metric are

compared to the total amount of ozone

above the NAAQS (i.e., 125 ppb, 1-hour

or 85 ppb, 8-hour) in the Base Case. This

baseline measure of the ‘‘total amount of

nonattainment’’ (i.e., the total ‘‘ppb’’ of

ozone that is above the NAAQS) is

calculated by summing the ‘‘ppb’’

values in the Base Case that are above

the level of the NAAQS. The total

contribution from an upwind State to a

particular downwind area calculated by

Metric 3 is expressed in relation to the
Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations 57389

43As described in the Air Quality Modeling TSD,

the metrics calculated using the hourly

contributions >= 125 ppb are consistent with the

metrics calculated using 1-hour daily maximum

contributions >= 125 ppb. Similarly, the metrics

calculated using all 8-hour periods >= 85 ppb are

consistent with the metrics calculated using 8-hour

daily maximum values >= 85 ppb.

amount that the downwind area is in

nonattainment. For example, if Upwind

State #1 contributes a total of 50 ppb

>=125 ppb to Downwind Area #2 and

the total Base Case ozone >=125 ppb in

Downwind Area #2 is 500 ppb, then the

contribution from Upwind State #1 (i.e.,

50 ppb) to Downwind Area #2 is

equivalent to 10 percent of Downwind

Area #2’s nonattainment problem (i.e.,

50 ppb divided by 500 ppb, times 100).

UAM–V Metric 4: PopulationWeighted Total ppb Reduced. This

metric is similar to the ‘‘Total ppb

Reduced’’ metric except that the

calculated contributions are weighted

by (i.e., multiplied by) population. In

calculating this metric, the ‘‘ppb’’

contributions are determined for each

nonattainment receptor, then summed

across all nonattainment receptors in a

particular downwind area. During this

calculation, the population in the

nonattainment receptor is multiplied by

the total contribution in that receptor

(i.e., grid cell) and then this value is

added to the corresponding values for

the other receptors in the downwind

area. The results for this metric are

expressed relative to the populationweighted Base Case amount similar to

the approach followed with Metric 3, as

described above.

(2) CAMx Source Apportionment

Modeling. In the CAMx modeling, the

source apportionment technique was

used to calculate the contributions from

upwind States to ozone concentrations

above the NAAQS in downwind areas.

Due to computational constraints, it was

not possible for EPA to treat each State

in the OTAG region as a separate source

area. Several of the smaller States in the

Northeast were grouped together as

were seven States in the far western

portion of the region. The following

States were treated as individual source

areas:

• Alabama, Florida, Georgia, Illinois,

Indiana, Iowa, Kentucky, Louisiana,

Maine, Massachusetts, Michigan,

Mississippi, Missouri, New Jersey, New

York, North Carolina, Ohio,

Pennsylvania, South Carolina,

Tennessee, Texas, Virginia, West

Virginia, and Wisconsin.

The following States were grouped

together:

• Connecticut and Rhode Island were

combined; Maryland, Delaware and the

District of Columbia were combined;

New Hampshire and Vermont were

combined; and Arkansas was combined

with the portions of Oklahoma, Kansas,

Minnesota, Nebraska, North Dakota, and

South Dakota that lie within the OTAG

region.

The contributions from each of these

source areas to downwind

nonattainment were evaluated using

four metrics. As indicated above, the

CAMx metrics are calculated for the

same types of nonattainment receptors

as the UAM–V zero-out metrics. The

CAMx metrics are calculated in a way

that is different from the metrics used

for the zero-out runs in large part

because of the differences between the

two techniques. The zero-out modeling

calculates contributions using the

difference in predictions between two

model runs (i.e., a Base Case and a

State-specific zero-out run). In contrast,

the CAMx source apportionment

technique calculates contributions by

internally tracking ozone formed from

emissions in each source area. In raw

form, the source apportionment

technique produces a ‘‘ppb’’

contribution from each source area to

hourly ozone in each receptor grid cell.

The individual hourly ‘‘ppb’’

contributions were treated in the way

described below to calculate 1-hour and

8-hour values for the four metrics. The

approach was based on

recommendations to EPA by Environ,

the developers of CAMx. For 1-hour

concentrations the metrics are

calculated based on contributions to all

hourly predictions >=125 ppb. For 8-

hour concentrations, the metrics are

calculated based on the contribution to

every 8-hour period in a day with an

average concentration >=85 ppb. In

order to provide a link to the way 1-

hour and 8-hour concentrations were

treated for the zero-out runs, EPA also

calculated the CAMx metrics for 1-hour

daily maximum values >=125 ppb and

8-hour daily maximum values >=85

ppb. 43 The full set of results for all of

the CAMx metrics is contained in the

Air Quality Modeling TSD.

The CAMx Metrics 1 and 2 provide

information on the magnitude and

frequency of contributions in a form that

is similar to UAM–V Metrics 1 and 2.

CAMx Metric 3: Highest Daily

Average Contribution. This metric is the

highest daily average ozone ‘‘ppb’’

contribution from each upwind source

area to each downwind nonattainment

receptor area over all days modeled in

all four episodes. The following

example illustrates how this metric is

calculated for 1-hour ozone

concentrations. Similar procedures are

followed for calculating this metric for

8-hour concentrations. First, the hourly

‘‘ppb’’ contributions from a particular

upwind source area to each

nonattainment receptor in a downwind

area are summed across all receptors in

the downwind area. This total daily

contribution is then divided by the

number of hours and grid cells >=125

ppb in the downwind area to determine

the daily average ‘‘ppb’’ contribution.

This calculation is performed on a day

by day basis for each day in the 4

episodes. After the average

contributions are calculated for each

day, the highest daily average value

across all episodes is selected for

analysis. In addition, the highest daily

average contribution is expressed as a

percent of the downwind area’s average

ozone >=125 ppb. That is, the highest

daily average ‘‘ppb’’ contribution is

divided by the average of the ozone

concentrations >=125 ppb on that day

(i.e., the day on which the highest

average ppb contribution occurred). For

example, if the highest daily average

contribution from an upwind State to

nonattainment downwind is 15 ppb and

the average of the hourly ozone values

>=125 ppb on this day in the downwind

area is 150 ppb, then the 15 ppb

contribution, expressed as a percent, is

10 percent.

CAMx Metric 4: Percent of Total

Manmade Ozone Contribution. This

metric represents the total contribution

from emissions in an upwind State

relative to the total ozone for all hours

above the NAAQS in the downwind

area. This metric, which is referred to as

the ‘‘average contribution,’’ is calculated

for each episode as well as for all four

episodes combined. The following

example is used to illustrate how this

metric is calculated for a single episode

for a particular downwind area. In step

1, all predicted Base Case hourly values

>=125 ppb in the downwind area are

summed over all nonattainment

receptors and all days in an episode. In

step 2, the ‘‘ppb’’ contributions from a

source area to this downwind area are

summed over all nonattainment

receptors in the downwind area and all

days in the episode to yield a total ppb

contribution. The total contribution

calculated in Step 2 is then divided by

the total ozone >=125 ppb in the

downwind area to produce the fraction

of ozone >=125 ppb in the downwind

area that is due to emissions from the

upwind source area. This fraction is

multiplied by 100 to express the result

as a percent.

4. Confirmation of States Making a

Significant Contribution to Downwind

Nonattainment

In the proposal, EPA made findings of

significant contribution based on a
57390 Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations

44The approach for dealing with the 15 States in

the OTAG domain which were not proposed to

make a significant contribution to downwind

nonattainment are discussed below in Section

II.C.5, States Not Covered by this Rulemaking.

45Scenarios (b) and (c) refer to the runs used to

assess transport as described in Section IV.

46This information represents the average

contributions across all four episodes. In addition

to the four-episode average contribution, EPA also

examined the highest single-episode average

contribution from each upwind State to each

downwind area.

47The factors used to interpret the metrics should

not be confused with the multi-factor approach

used to identify the amounts of NOX emissions that

contribute signficantly to nonattainment.

weight-of-evidence approach that

included consideration of air quality

contributions based on subregional

modeling. As discussed in section II.C.2,

Summary of Notice of Proposed

Rulemaking Weight-of-Evidence

Approach, EPA believes that the

subregional modeling provides an

adequate independent basis for

determining which States contribute

significantly to downwind

nonattainment. The evaluation of the

State-by-State modeling confirms the

overall findings that were based on the

subregional modeling and provides

more refined information regarding the

impacts of specific upwind States on

nonattainment in individual downwind

areas. This State-by-State modeling is

discussed in more detail below.

a. Analysis Approach. The EPA has

analyzed the results of the State-by-State

UAM–V zero-out modeling and the

State-by-State CAMx source

apportionment modeling for each of the

23 jurisdictions for which this modeling

is available.44 Both UAM–V and CAMx

modeling results are available for fifteen

States (i.e., Alabama, Georgia, Illinois,

Indiana, Kentucky, Massachusetts,

Michigan, Missouri, North Carolina,

Ohio, South Carolina, Tennessee,

Virginia, West Virginia, and Wisconsin).

For an additional eight States (i.e.,

Connecticut, Delaware, the District of

Columbia, Maryland, New Jersey, New

York, Pennsylvania, and Rhode Island),

CAMx modeling is available. Also, as

noted above in Section II.C.3, State-byState Air Quality Modeling, Connecticut

and Rhode Island were combined as a

single source area, and Maryland, the

District of Columbia, and Delaware were

also combined as a single source area.

Because the NOX emissions and/or NOX

emissions density is large in each

jurisdiction within both of these

combined source areas, EPA believes

that the downwind contributions from

these combined source areas can be

attributed to each jurisdiction within

the source area.

For the 1-hour NAAQS, EPA

evaluated downwind impacts in two

ways using the factors described in

Section II.C.3, State-by-State Air Quality

Modeling. First, EPA evaluated the

contributions from each upwind State to

nonattainment in each downwind State.

Second, the EPA evaluated the

contributions from each upwind State to

nonattainment in each downwind 1-

hour nonattainment area. In downwind

States which only contain a single

intrastate nonattainment area (e.g.,

Atlanta), the results of the downwind

State and downwind nonattainment

area analyses are the same because the

same nonattainment receptors are used

in both cases. For the 8-hour NAAQS,

EPA evaluated the contributions from

upwind States to 8-hour nonattainment

in each downwind State.

The EPA used the following process

in determining whether a particular

upwind State contributes significantly

to 1-hour nonattainment in an

individual downwind area. First, EPA

reviewed the extent of the

nonattainment problem in the

downwind area using ambient design

values and model predictions of future

ozone concentrations after the

application of (a) 2007 Base Case

controls, (b) additional local NOX

reductions, and (c) regional reductions

(additional local plus upwind NOX

reductions).45 As indicated above, EPA

determined that each downwind area

had a residual nonattainment problem

even after implementation of the control

measures in the 2007 Base Case.

Second, using the information from

CAMx Metric 4 46, EPA reviewed (a) the

relative portion of the ozone problem in

each downwind area that is due to

‘‘local’’ emissions (i.e., emissions from

the entire State or States in which the

downwind area is located), (b) the total

contribution from all upwind emissions

(i.e., the sum of the contributions from

manmade emissions in all upwind

States, combined), and (c) the

contribution from manmade emissions

in individual upwind States. The local

versus upwind contributions for each

downwind area are provided in the Air

Quality Modeling TSD. The EPA

analyzed this information to determine

whether upwind emissions are an

important part of the downwind areas’

nonattainment problem. In general, the

data indicate that, although a substantial

portion of the 1-hour nonattainment

problem in many of the downwind areas

is due to local emissions, a substantial

portion of the nonattainment problem is

also due to emissions from upwind

States. In addition, for most upwindState-to-downwind-area linkages there

is no single upwind State that makes up

all of the upwind contribution. Rather,

the total contribution for all upwind

States combined is comprised of

individual contributions from a number

of upwind States many of which are

relatively similar in magnitude such

that there is no ‘‘bright line’’ which

distinguishes between the contributions

from most of the individual upwind

States.

Third, EPA determined whether each

individual upwind State significantly

contributes to nonattainment in a

particular downwind area using the

UAM–V and CAMx metrics to evaluate

three aspects, or factors of the

contribution.47 These factors include the

magnitude, frequency, and relative

amount of the contribution. The specific

UAM–V and CAMx metrics which

correspond to each of the factors are

identified in Table II–2. As indicated in

the table, there is at least one metric

from each modeling technique that

corresponds to each of the three factors.

TABLE II–2.—METRICS ASSOCIATED WITH EACH CONTRIBUTION FACTOR

Factor UAM–V CAMx

Magnitude of Contribution .... Maximum ‘‘ppb’’ contribution (Metric 2) Maximum ‘‘ppb’’ Contribution (Metric 2); and Highest

Daily Average Contribution (Metric 3).

Frequency of Contribution .... Number and percent of exceedences with contributions

in various concentration ranges (Metric 1 and 2)

Number and percent of exceedences with contributions

in various concentration ranges (Metric 1 and 2).

Relative Amount of Contribution.Total ‘‘ppb’’ contribution relative to the total ‘‘ppb’’ that

the downwind area is above the NAAQS (Metric 3);

and Total population-weighted ‘‘ppb’’ contribution relative to the total population-weighted ‘‘ppb’’ that the

downwind area is above the NAAQS (Metric 4)

Four-episode average percent contribution from the

upwind State to nonattainment in the downwind area

(Metric 4); and Highest single-episode average percent contribution from the upwind State to nonattainment in the downwind area (Metric 4).
Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations 57391

48This is further described in the Air Quality

Modeling TSD.

It should be noted that the relative

contributions of individual upwind

States to a particular downwind area

add up to 100 percent for the CAMx 4-

episode average percent contribution.

However, this is not the case for the

CAMx highest single-episode average

percent contribution since the value

from one upwind State can occur in a

different episode than the value from

another upwind State for the same

downwind area. In addition, it should

be noted that UAM–V Metrics 3 and 4

are used in combination to express the

total contribution above the NAAQS

relative to the total amount that the

downwind area is above the NAAQS.

The values for each of these metrics also

do not add up to 100 percent when

considering contributions from multiple

upwind States to an individual

downwind area.

The EPA compiled the UAM-V and

CAMx metrics by downwind area in

order to evaluate the contributions to

downwind nonattainment. The data on

1-hour and 8-hour contributions were

compiled and analyzed separately. The

data were reviewed to determine how

large of a contribution a particular

upwind State makes to nonattainment

in each downwind area in terms of the

magnitude of the contribution and the

relative amount of the total

contribution. The data were also

examined to determine how frequently

the contributions occur.

The first step in evaluating this

information was to screen out linkages

for which the contributions were very

low, as described in the Air Quality

Modeling TSD. The finding of

significance for linkages that passed the

initial screening criteria was based on

EPA’s technical assessment of the

values for the three contribution factors.

Each upwind State that had large and/

or frequent contributions to the

downwind area, based on these factors,

is considered as contributing

significantly to nonattainment in the

downwind area. The EPA believes that

each of the factors provides an

independent legitimate measure of

contribution. However, there had to be

multiple factors that indicate large and/

or frequent contributions in order for

the linkage to be significant. In this

regard, the finding of a significant

contribution for an individual linkage

was not based on any single factor.

For many of the individual linkages

the factors yield a consistent result (i.e.,

either large and/or frequent

contributions or small and/or infrequent

contributions). In some cases, however,

not all of the factors are consistent. For

upwind-downwind linkages in which

some of the factors indicate high and/or

frequent contributions while other

factors do not, EPA considered the

overall number and magnitude of those

factors that indicate large and/or

frequent contributions compared to

those factors that do not. Based on an

assessment of all the factors in such

cases, EPA determined that the upwind

State contributes significantly to

nonattainment in the downwind area if

on balance the factors indicate large

and/or frequent contributions from the

upwind State to the downwind area.

The EPA’s evaluation of the

contributions to 1-hour nonattainment

in New York City is presented as an

example to illustrate this process. The

New York City area, which consists of

portions of New York, New Jersey, and

Connecticut, is designated as a severe

nonattainment area under the 1-hour

NAAQS. The ambient 1-hour design

value in New York City, based on 1994

through 1996 monitoring data is 144

ppb. During the four OTAG episodes, 39

percent of the days are predicted to have

1-hour exceedences in 2007 after the

implementation of all CAA controls and

Federal measures.48 Moreover, EPA’s air

quality modeling of the benefits of

regional NOX strategies, as described in

Section IV, Air Quality Assessment,

indicates that there would still be

exceedences of the 1-hour NAAQS

remaining in New York City even with

eliminating the significant amounts of

emissions required by this NOX SIP

Call.

In the assessment of contributions to

New York City, EPA examined the local

versus upwind contributions to 1-hour

nonattainment in this area, as shown in

Table II–3. Local emissions in the New

York City nonattainment area are spread

among numerous stationary sources,

area sources, highway sources, and

nonroad sources, each of which

contributes only a very small, indeed

sometimes immeasurable, amount to

New York City’s ozone nonattainment

problem. Combined, these emissions

result in approximately 55 percent of

the New York City area’s ozone

problem. Emissions from States upwind

of New York, New Jersey, and

Connecticut, on average across all four

episodes, contribute 45 percent of the

nonattainment problem in New York

City is due to. However, no single State

stands out as contributing most of the

total upwind contribution. The biggest

single contributor is Pennsylvania (18

percent) followed by Maryland/

Washington, DC/Delaware (5 percent).

The total contribution from all

Northeast States is 23 percent. A similar

amount (22 percent) of the total

contribution is due to emissions in

those States outside the Northeast. The

data in Table II–3 indicate that 19

percent of the 22 percent is fairly evenly

divided among ten States, whose

contributions range from 1 percent (6

States) to 4 percent (Ohio and Virginia).

The remaining 3 percent (i.e., 19 percent

vs 22 percent) is from States that each

contribute less than 1 percent, on

average. The highest single-episode

contributions from States upwind of the

Northeast range from 1 percent

(Tennessee) to 8 percent (Virginia). In

general, the contribution data in Table

II–3 indicate that a substantial amount

of New York City’s nonattainment

problem is due to the collective

contribution from emissions in a

number of upwind States both within

and outside the northeast. That these

upwind contributions are a meaningful

part of New York City’s nonattainment

problem is particularly evident in light

of the fact that the contribution to the

problem made by New York City itself

is comprised of the collective

contribution of numerous sources.

TABLE II–3.—PERCENT CONTRIBUTION FROM UPWIND STATES TO 1-HOUR NONATTAINMENT IN NEW YORK CITY 1

Downwind area: New York City

Percent of

total manmade

emissions

over 4 episodes

Highest singleepisode percent

contribution 2

Amount due to ‘‘Local’’ Emissions 3 ......................................................................................................................... 55 4NA

Total Amount from all ‘‘Upwind’’ States ................................................................................................................... 45 NA

Contributions from Individual Upwind States ........................................................................................................... ........................ ........................

PA ............................................................................................................................................................................. 18 19

MD/DC/DE ................................................................................................................................................................ 5 6
57392 Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations

49For New York City, each of the ‘‘Group 2’’

States were found to make a significant

contribution. However, this was not the case for all

of the Group 2 linkages in other nonattainment

areas. For example, the contribution from Kentucky

to Philadelphia and the contribution from

Tennessee to Baltimore were Group 2 situations in

which EPA determined that the contributions were

not significant.

TABLE II–3.—PERCENT CONTRIBUTION FROM UPWIND STATES TO 1-HOUR NONATTAINMENT IN NEW YORK CITY 1—

Continued

Downwind area: New York City

Percent of

total manmade

emissions

over 4 episodes

Highest singleepisode percent

contribution 2

OH ............................................................................................................................................................................ 4 6

VA ............................................................................................................................................................................. 4 8

WV ............................................................................................................................................................................ 3 7

IL .............................................................................................................................................................................. 2 3

IN .............................................................................................................................................................................. 1 2

KY ............................................................................................................................................................................. 1 3

MI ............................................................................................................................................................................. 1 4

MO ............................................................................................................................................................................ 1 2

NC ............................................................................................................................................................................ 1 2

TN ............................................................................................................................................................................. 1 1

Total Amount from All Other States, combined ....................................................................................................... 3 NA.

1These values are based on CAMx Metric 3 calculated across all 4 episodes.

2These values are based on CAMx Metric 3 calculated for each episode individually. These values do not add up to 100 percent.

3 3. Total contribution from the State(s) in which the Nonattainment area is located.

4 4. Not applicable.

The extent of New York City’s

nonattainment problem and the nature

of the contributions from upwind States

were considered in determining

whether the values of the metrics

indicate large and/or frequent

contributions for individual upwind

States. Specifically, additional controls

beyond the local and upwind NOX

reductions which are part of the

regional NOX strategy may be needed to

solve New York City’s 1-hour

nonattainment problem. Also, the total

contribution from all upwind States is

large and there is no single State or

small number of States which comprise

this total upwind portion. In this regard,

the contributions to New York City from

some States may not appear to be

individually ‘‘high’’ amounts. However,

(as described below) these

contributions, when considered together

with the contributions from other States

(i.e., the collective contribution)

produce a large total contribution to

nonattainment in New York City.

The EPA evaluated the magnitude,

frequency, and relative amount of

contribution from emissions in

individual upwind States to determine

which States contribute significantly to

1-hour nonattainment in New York City.

The UAM–V and CAMx metrics which

quantify each upwind State’s

contribution to New York City for each

of the three factors are provided in the

Air Quality Modeling TSD and

described below. Examination of the

values for these metrics indicates that

the upwind States can be divided into

three general groups, based on the

magnitude, frequency, and relative

amount of contribution. The first group

contains those upwind States for which

the UAM–V and CAMx metrics all

clearly indicate a significant

contribution to 1-hour nonattainment in

New York City. The second group

contains those States for which the

CAMx and UAM–V metrics are not

quite as consistent, but overall the

metrics indicate a significant

contribution to 1-hour nonattainment in

New York City.49 The third group

contains those States for which the

CAMx and UAM–V metrics clearly

indicate that the impacts do not make a

significant contribution to New York

City.

Group 1 Upwind States:

The CAMx and UAM–V metrics all

clearly indicate that emissions from

Maryland/Washington, DC/Delaware,

Ohio, Pennsylvania, Virginia, and West

Virginia make large and/or frequent

contributions to 1-hour nonattainment

in New York City. For Pennsylvania the

magnitude of contribution, as indicated

by the highest daily average

contribution (CAMx Metric 3), is 25 ppb

and the relative amount of contribution

is 18 percent (CAMx Metric 4). For the

other upwind areas, the magnitude of

the contributions range from 9 ppb to 15

ppb (CAMx Metric 3, highest daily

average contributions) with

contributions in the range of 5 ppb to 10

ppb—from Ohio, Virginia, and West

Virginia (UAM–V Metric 2, maximum

‘‘ppb’’ contribution). In terms of the

frequency of the contribution, 7 percent

to 11 percent of the total number of gridhours >=125 ppb in New York City

receive contributions of 10 ppb from

each of these States (CAMx Metric 1 and

2). Also, the relative amounts of the

contribution are in the range of 6

percent to 8 percent (CAMx Metric 4,

highest single-episode average percent

contribution) and the total contribution

from each of three States (i.e., Ohio,

Virginia, and West Virginia) is large

compared to the total amount of

nonattainment, ranging from 8 percent

to 11 percent (UAM–V Metric 3).

Group 2 Upwind States:

The CAMx and UAM–V metrics are

somewhat less consistent on the extent

of contributions from each of 5 States:

Kentucky, Illinois, Indiana, Michigan,

and North Carolina. None of the metrics

for either model indicate extremely low

or extremely high contributions. Rather,

for these States most of the metrics

indicate relatively high contributions

while a few metrics indicate relatively

low contributions. The rationale used by

EPA for evaluating the contributions

from these States involved comparing

and contrasting each piece of data for

these States on an individual ‘‘upwind

State-by-upwind State’’ basis and as a

group (i.e., for all 5 States, together) in

order to weigh the relative magnitude

and frequency of the contributions for

making a determination of significance.

UAM–V Metrics—For each of these 5

States the ‘‘weakest’’ factor is the

magnitude contribution (UAM–V Metric

2) in that the highest contributions are

in the range of 2 to 5 ppb. The other

UAM–V Metrics, however, indicate that

the contributions from each State are of

a larger frequency and relative amount.

Specifically, four of these States

(Kentucky, Indiana, Illinois, and
Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations 57393

Michigan) each contribute 2 to 5 ppb to

as many as 3 percent to 4 percent of the

exceedences in New York City (UAM–

V Metrics 1 and 2). While North

Carolina contributes to somewhat fewer

exceedences (2 percent), this slight

weakness is out-weighed by the relative

amount of contribution (UAM–V

Metrics 3 and 4) which indicates that

the total contribution from North

Carolina alone is equivalent to 3 percent

of the total ‘‘ppb’’ >=125 ppb and 4

percent of the population-weighted

‘‘ppb’’ >=125 ppb in New York City. For

Indiana, Illinois, and Michigan the

relative amount of contribution (UAM–

V Metrics 3 and 4) is also relatively high

and ranges from 3 percent to 5 percent.

The relative amount of contribution

from Kentucky is somewhat weaker at 2

percent.

CAMx Metrics—For Illinois, all of the

CAMx metrics indicate relatively large

and/or frequent contributions, as

described below. For Kentucky, Indiana,

Michigan, and North Carolina the

magnitude of contribution is large, as

indicated by the maximum contribution

which ranges from 6 ppb (Indiana) to 11

ppb (North Carolina). Also, the highest

daily average contribution from

Kentucky, Michigan, and North Carolina

are all in the range of 5 ppb to 7 ppb.

In terms of the frequency of

contribution, Indiana and North

Carolina contribute in the range of 5 ppb

to 10 ppb to 3 percent and 6 percent of

the exceedences, respectively, in New

York City. For Kentucky, Indiana,

Michigan, and North Carolina the

relative amounts of contribution is

somewhat mixed in that the 4-episode

average percent contribution is only 1

percent, but the highest single-episode

average percent contributions are higher

at 2 percent from both Indiana and

North Carolina, 3 percent from

Kentucky, and 4 percent from Michigan

(CAMx Metric 4).

Overall contributions considering

UAM–V and CAMx Metrics—

Considering the CAMx and UAM–V

metrics, as described below, the

majority of the contribution factors

indicate that, overall, each of the Group

2 States contributes significantly to 1-

hour nonattainment in New York City.

Kentucky—

Metrics indicating relatively high

and/or frequent contributions:

—Magnitude of Contribution: the

maximum contribution from CAMx is

9 ppb (CAMx Metric 2) and highest

daily average contribution is 7 ppb

(CAMx Metric 3);

—Frequency of Contribution: 4 percent

of the exceedences receive

contributions of more than 2 ppb

(UAM–V Metrics 1 and 2); and

—Relative Amount of Contribution: the

highest single-episode average

contribution is 3 percent (CAMx

Metric 4).

Metrics indicating relatively low and/

or infrequent contributions:

—Magnitude of Contribution: the

maximum contribution from UAM–V

is 2 ppb; and

—Relative Amount of Contribution: the

4-episode average percent

contribution is 1 percent (CAMx

Metric 4).

Indiana—

Metrics indicating relatively high

and/or frequent contributions:

—Magnitude of Contribution: the

maximum ‘‘ppb’’ contribution is 6

ppb (CAMx Metric 2);

—Frequency of Contribution: 4 percent

of the exceedences receive

contributions of more than 2 ppb

(UAM–V Metrics 1 and 2) ; and

—Relative Amount of Contribution: the

total ‘‘ppb’’ contribution is equivalent

to 3 percent of total amount of

nonattainment (UAM–V Metric 3).

Metrics indicating relatively low and/

or infrequent contributions:

—Magnitude of Contribution: the

maximum contribution from is 2 ppb

(UAM–V Metric 2); and

—Relative Amount of Contribution: the

4-episode average percent

contribution is 1 percent (CAMx

Metric 4).

Illinois—

Metrics indicating relatively high

and/or frequent contributions:

—Magnitude of Contribution: the

maximum contribution is 8 ppb

(CAMx Metric 2); the highest daily

average contribution is 6 ppb;

—Frequency of Contribution: 3 percent

of the exceedences receive

contributions of more than 2 ppb; and

—Relative Amount of Contribution: the

highest single-episode average

contribution is 3 percent (CAMx

Metric 4); the total ‘‘ppb’’ contribution

is equivalent to 3 percent of total

amount of nonattainment.

Metrics indicating relatively low and/

or infrequent contributions:

—Magnitude of Contribution: the

maximum contribution from UAM–V

is 2 ppb.

Michigan—

Metrics indicating relatively high

and/or frequent contributions:

—Magnitude of Contribution: the

maximum contribution is 7 ppb

(CAMx Metric 2); the highest daily

average contribution is 5 ppb (CAMx

Metric 3);

—Frequency of Contribution: 3 percent

of the exceedences receive

contributions of more than 2 ppb

(UAM–V Metrics 1 and 2); and

—Relative Amount of Contribution: the

highest single-episode average

contribution is 4 percent (CAMx

Metric 4); the total ‘‘ppb’’ contribution

is equivalent to 3 percent of the total

amount of nonattainment.

Metrics indicating relatively low and/

or infrequent contributions:

—Magnitude of Contribution: the

maximum contribution from UAM–V

is 2 ppb

—Frequency of Contribution: 1 percent

of the exceedences receive

contributions of 5 ppb or more (CAMx

Metrics 1 and 2); and

—Relative Amount of Contribution: the

4-episode average percent

contribution is 1 percent (CAMx

Metric 4).

North Carolina—

Metrics indicating relatively high

and/or frequent contributions:

—Magnitude of Contribution: the

maximum contribution is 11 ppb

(CAMx Metric 2); the highest daily

average contribution is 6 ppb (CAMx

Metric 3);

—Frequency of Contribution: 6 percent

of exceedences receive contributions

of 5 ppb or more (CAMx Metrics 1

and 2); and

—Relative Amount of Contribution: the

total ‘‘ppb’’ contribution is equivalent

to 3 percent of total amount of

nonattainment.

Metrics indicating relatively low and/

or infrequent contributions:

—Relative Amount of Contribution: the

4-episode average percent

contribution is 1 percent (CAMx

Metric 4).

Group 3 Upwind States: The CAMx

and UAM–V metrics clearly indicate

that the emissions from the following

States do not make large and/or frequent

contributions to 1-hour nonattainment

in New York City: Alabama, Georgia,

Massachusetts, Missouri, South

Carolina, Tennessee, and Wisconsin.

The rationale for this conclusion is as

follows:

—Magnitude of Contribution: all of

these upwind States individually

contribute less than 2 ppb to 1-hour

daily maximum exceedences in New

York City (UAM–V Metric 2); the

highest daily average contribution

was 1 ppb or less from Alabama,

Georgia, and Massachusetts, and 2
57394 Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations

ppb from South Carolina, Tennessee,

and Wisconsin (CAMx Metric 3); and

—Relative Amount of Contribution: the

4-episode average contributions from

Alabama, Georgia, Massachusetts,

South Carolina, and Wisconsin are

less than 1 percent (CAMx Metric 4);

the total contributions from Missouri

and Tennessee are each equivalent to

1 percent of the total amount of

nonattainment in New York City

(UAM–V Metric 3).

Based on the preceding evaluation,

EPA believes that emissions in each of

the following twelve jurisdictions

contribute significantly to 1-hour

nonattainment in the New York City

nonattainment area: the District of

Columbia, Delaware, Illinois, Indiana,

Kentucky, Maryland, Michigan, North

Carolina, Ohio, Pennsylvania, Virginia,

and West Virginia.

b. States Which Contain Sources That

Significantly Contribute to Downwind

Nonattainment. The results of EPA’s

assessment of the State-by-State UAM–

V and CAMx modeling confirms the

findings based on subregional modeling

that the 23 jurisdictions contribute large

and/or frequent amounts to downwind

nonattainment under both the 1-hour

and 8-hour NAAQS and forms an

independent basis for those findings.

The specific upwind States which

significantly contribute to

nonattainment in specific downwind

States are listed in Tables II–4 and II–

5 for the 1-hour NAAQS and Table II–

6 and Table II–7 for the 8-hour NAAQS.

The information on the 1-hour

contribution linkages are presented by

upwind State in Table II–4 and by

downwind State in Table II–5. In Table

II–4 the upwind States are each listed in

the first column and the downwind

States to which each upwind State

contributes significantly are listed in the

second column. In Table II–5, the same

information is presented by downwind

State. In this table, each downwind

State is listed in the first column and

the upwind States that contribute to that

downwind State are listed in the second

column. The 8-hour contribution

linkages are presented by upwind State

in Table II–6 and by downwind State in

Table II–7.

TABLE II–4.—DOWNWIND STATES FOR WHICH UPWIND STATES CONTAIN SOURCES THAT CONTRIBUTE SIGNIFICANTLY TO

1-HR NONATTAINMENT 1

Upwind state Downwind states

Alabama .............................................................. GA, IL*, IN*, MI*, TN, WI*.

Connecticut ......................................................... ME, MA, NH.

Delaware ............................................................. CT, ME, MA, NH*, NJ, NY, PA, RI, VA.

District of Columbia ............................................. CT, ME, MA, NH*, NJ, NY, PA, RI, VA.

Georgia ............................................................... AL, TN.

Illinois .................................................................. CT*, IN, MD, NJ*, NY, MI, MO, WI*.

Indiana ................................................................ CT*, DE*, DC*, IL*, KY, MD, NJ*, NY, MI, OH, VA*, WI*.

Kentucky ............................................................. AL, CT*, DC*, GA, IL*, IN, MD, MI*, NJ, NY, MO, OH, VA, WI*.

Maryland ............................................................. CT, ME, MA, NH*, NJ, NY, PA, RI, VA.

Massachusetts .................................................... ME, NH.

Michigan .............................................................. CT, DC*, MD, NJ, NY, VA*.

Missouri ............................................................... IL, IN, MI, WI*.

New Jersey ......................................................... CT, ME, MA, NH, NY, PA, RI.

New York ............................................................ CT, ME, MA, NH, NJ, RI.

North Carolina ..................................................... CT*, DC*, GA, KY, MD, NJ, NY, OH, PA, VA*.

Ohio ..................................................................... CT, DE, DC*, KY, MD, MA, NH*, NJ, NY, PA, RI, VA.

Pennsylvania ....................................................... CT, DE, DC, ME, MD, MA, NH, NJ, NY, RI, VA.

Rhode Island ....................................................... ME, MA, NH.

South Carolina .................................................... AL, GA, TN.

Tennessee .......................................................... AL, GA, IL*, IN, KY, MI*, OH, WI*.

Virginia ................................................................ CT, DE, DC, KY*, MD, MA, NH*, NJ, NY, PA, RI.

West Virginia ....................................................... CT, DE, DC, MD, MA, NJ, NY, PA, RI, VA.

Wisconsin ............................................................ IL*, IN*, MI* .

1States marked with an asterisk (*) are included because they are part of an interstate nonattainment area that receives a contribution from

the upwind State. New Hampshire is included because it is part of the combined Boston/Portsmouth area; Connecticut and New Jersey are included because they are part of the New York City area; Kentucky is included because it is part of the Cincinnati area; Delaware is included because it is part of the Philadelphia area; Illinois is included because it is part of the St. Louis area; Illinois, Indiana, Michigan, and Wisconsin are

included because they are part of the Lake Michigan area; and Maryland, Virginia, and the District of Columbia are included because they are

part of the Washington, DC area.

TABLE II–5.—UPWIND STATES THAT CONTAIN SOURCES THAT CONTRIBUTE SIGNIFICANTLY TO 1-HR NONATTAINMENT IN

DOWNWIND STATES 1

Downwind state Upwind states

Alabama .............................................................. GA, KY, SC, TN.

Connecticut ......................................................... DE, DC, IL*, IN*, KY*, MD, MI*, NJ, NY, NC*, OH, PA, VA, WV.

Delaware ............................................................. IN*, OH, PA, VA, WV.

District of Columbia ............................................. IN*, KY*, MI*, NC*, OH*, PA, VA, WV.

Georgia ............................................................... AL, KY, NC, SC, TN.

Illinois .................................................................. AL*, IN*, KY*, MO, TN*, WI*.

Indiana ................................................................ AL*, IL, KY, MO, TN, WI*.

Kentucky ............................................................. IN, NC, OH, TN, VA*.

Maine .................................................................. CT, DE, DC, MD, MA, NJ, NY, PA, RI.

Maryland ............................................................. IL, IN, KY, MI, NC, OH, PA, VA, WV.

Massachusetts .................................................... CT, DE, DC, MD, NJ, NY, OH, PA, RI, VA, WV.

Michigan .............................................................. AL*, IL, IN, KY*, MO, TN*, WI*.

Missouri ............................................................... IL, KY.
Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations 57395

TABLE II–5.—UPWIND STATES THAT CONTAIN SOURCES THAT CONTRIBUTE SIGNIFICANTLY TO 1-HR NONATTAINMENT IN

DOWNWIND STATES 1—Continued

Downwind state Upwind states

New Hampshire .................................................. CT, DC*, DE*, MD*, MA, NJ, NY, OH*, PA, RI, VA*.

New Jersey ......................................................... DE, DC, IL*, IN*, KY, MD, MI, NY, NC, OH, PA, VA, WV.

New York ............................................................ DE, DC, IL, IN, KY, MD, MI, NJ, NC, OH, PA, VA, WV.

Ohio ..................................................................... IN, KY, TN, NC.

Pennsylvania ....................................................... DE, DC, MD, NJ, NC, OH, VA, WV.

Rhode Island ....................................................... DE, DC, MD, NJ, NY, OH, PA, VA, WV.

Tennessee .......................................................... AL, GA, SC.

Virginia ................................................................ DE, DC, IN*, KY, MD, MI*, NC*, OH, PA, WV.

Wisconsin ............................................................ AL*, IL*, IN*, KY*, MO*, TN* .

1 Upwind States marked with an asterisk (*) are considered to significantly contribute to the downwind State because they contribute to an

interstate nonattainment area that includes part of the downwind State. New Hampshire is included in the Boston/Portsmouth area; Connecticut

and New Jersey are included in the New York City area; Kentucky is included in the Cincinnati area; Delaware is included in the Philadelphia

area; Illinois is included in the St. Louis area; Illinois, Indiana, Michigan, and Wisconsin are included in the Lake Michigan area; and Maryland

and Virginia are included in the Washington, DC area.

TABLE II–6.—DOWNWIND STATES TO WHICH SOURCES IN UPWIND STATES CONTRIBUTE SIGNIFICANTLY FOR THE 8-HOUR

STANDARD

Upwind state Downwind states

Alabama .............................................................. GA, IL, IN, KY, MI, MO, NC, OH, PA, SC, TN, VA.

Connecticut ......................................................... ME, MA, NH, RI.

Delaware ............................................................. CT, ME, MA, NH, NJ, NY, PA, RI, VA.

District of Columbia ............................................. CT, ME, MD, MA, NH, NJ, NY, PA, RI, VA.

Georgia ............................................................... AL, IL, IN, KY, MI, MO, NC, SC, TN, VA.

Illinois .................................................................. AL, CT, DC, DE, IN, KY, MD, MI, MO, NJ, NY, OH, PA, RI, TN, WV, WI.

Indiana ................................................................ DE, IL, KY, MD, MI, MO, NJ, NY, OH, PA, TN, VA, WV, WI.

Kentucky ............................................................. AL, DC, DE, GA, IL, IN, MD, MI, MO, NJ, NY, NC, OH, PA, SC, TN, VA, WV, WI.

Maryland ............................................................. CT, DE, DC, ME, MA, NH, NJ, NY, PA, RI, VA.

Massachusetts .................................................... ME, NH

Michigan .............................................................. CT, DC, DE, MD, MA, NJ, NY, OH, PA, WV.

Missouri ............................................................... IL, IN, KY, MI, OH, PA, TN, WI.

New Jersey ......................................................... CT, ME, MA, NH, NY, PA, RI.

New York ............................................................ CT, ME, MA, NH, NJ, PA, RI.

North Carolina ..................................................... AL, CT, DE, GA, IN, KY, ME, MD, MA, NJ, NY, OH, PA, RI, SC, TN, VA, WV.

Ohio ..................................................................... CT, DC, DE, IN, KY, MD, MA, MI, NJ, NY, NC, PA, RI, TN, VA, WV.

Pennsylvania ....................................................... CT, DC, DE, ME, MD, MA, NH, NJ, NY, OH, RI, VA.

Rhode Island ....................................................... ME, MA, NH.

South Carolina .................................................... AL, GA, IN, KY, NC, TN, VA.

Tennessee .......................................................... AL, DC, DE, GA, IL, IN, KY, MD, MI, MO, NC, OH, PA, SC, VA, WV, WI.

Virginia ................................................................ CT, DE, DC, ME, MD, MA, NJ, NY, NC, OH, PA, RI, SC, WV.

West Virginia ....................................................... CT, DC, DE, IN, KY, MD, MA, NJ, NY, NC, OH, PA, RI, SC, TN, VA.

Wisconsin ............................................................ MI.

TABLE II–7.—UPWIND STATES THAT CONTAIN SOURCES THAT CONTRIBUTE SIGNIFICANTLY TO 8-HOUR NONATTAINMENT IN

DOWNWIND STATES.

Downwind state Upwind states

Alabama .............................................................. GA, IL, KY, NC, SC, TN.

Connecticut ......................................................... DE, DC, IL, MD, MI, NJ, NY, NC, OH, PA, VA, WV.

District of Columbia ............................................. IL, KY, MD, MI, OH, PA, TN, VA, WV.

Delaware ............................................................. IL, IN, KY, MI, NC, OH, PA, TN, VA, WV.

Georgia ............................................................... AL, KY, NC, SC, TN.

Illinois .................................................................. AL, GA, IN, KY, MO, TN.

Indiana ................................................................ AL, GA, IL, KY, MO, NC, OH, SC, TN, WV.

Kentucky ............................................................. AL, GA, IL, IN, MO, NC, OH, SC, TN, WV.

Maine .................................................................. CT, DE, DC, MD, MA, NJ, NY, NC, PA, RI, VA

Maryland ............................................................. DC, IL, IN, KY, MI, NC, OH, PA, TN, VA, WV.

Massachusetts .................................................... CT, DE, DC, MD, MI, NJ, NY, NC, OH, PA, RI, VA, WV.

Michigan .............................................................. AL, GA, IL, IN, KY, MO, OH, TN, WI.

Missouri ............................................................... AL, GA, IL, IN, KY, TN.

New Hampshire .................................................. CT, DE, DC, MD, MA, NJ, NY, PA, RI.

New Jersey ......................................................... DE, DC, IL, IN, KY, MD, MI, NC, NY, OH, PA, VA, WV.

New York ............................................................ DE, DC, IL, IN, KY, MD, MI, NC, NJ, OH, PA, VA, WV.

North Carolina ..................................................... AL, GA, KY, OH, SC, TN, VA, WV.

Ohio ..................................................................... AL, IL, IN, KY, MI, MO, NC, PA, TN, VA, WV.

Pennsylvania ....................................................... AL, DE, DC, IL, IN, KY, MD, MI, MO, NJ, NY, NC, OH, TN, VA, WV.

Rhode Island ....................................................... CT, DE, DC, IL, MD, NJ, NY, NC, OH, PA, VA, WV.
57396 Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations

TABLE II–7.—UPWIND STATES THAT CONTAIN SOURCES THAT CONTRIBUTE SIGNIFICANTLY TO 8-HOUR NONATTAINMENT IN

DOWNWIND STATES.—Continued

Downwind state Upwind states

South Carolina .................................................... AL, GA, KY, NC, TN, VA, WV.

Tennessee .......................................................... AL, GA, IL, IN, KY, MO, NC, OH, SC, WV.

Virginia ................................................................ AL, DE, DC, GA, IN, KY, MD, NC, OH, PA, SC, TN, WV.

West Virginia ....................................................... IL, IN, KY, MI, NC, OH, TN, VA.

Wisconsin ............................................................ IL, IN, KY, MO, TN.

c. Examples of Contributions From

Upwind States to Downwind

Nonattainment. A full discussion of

EPA’s analysis supporting the

determination that specific upwind

States contribute significantly to

individual downwind States under the

1-hour and 8-hour NAAQS is provided

in the Air Quality Modeling TSD.

Examples of the types of contributions

which link individual upwind States to

downwind areas are provided below for

the 1-hour NAAQS for the 23 upwind

jurisdictions.

—Alabama’s Contribution to 1-Hour

Nonattainment in Atlanta

Magnitude of Contribution: The

maximum contribution is 39 ppb

(CAMx Metric 2); the highest daily

average contribution is 31 ppb (CAMx

Metric 3).

Frequency of Contribution: Alabama

contributes at least 10 ppb to 12 percent

of the 1-hr exceedences (UAM–V

Metrics 1 and 2).

Relative Amount: The total

contribution from Alabama is equivalent

to 14 percent of the total amount >=125

ppb in Atlanta (UAM–V Metric 3);

Alabama contributes 8 percent of the

total manmade ppb >= 125 ppb in

Atlanta (CAMx Metric 4; 4-episode

average percent contribution).

—Connecticut/Rhode Island’s

Contribution to 1-Hour Nonattainment

in Western Massachusetts

Magnitude of Contribution: The

maximum contribution is 61 ppb

(CAMx Metric 2); the highest daily

average contribution is 50 ppb (CAMx

Metric 3).

Frequency of Contribution:

Connecticut/Rhode Island contribute at

least 10 ppb to 100 percent of the 1-hr

exceedences (CAMx Metrics 1 and 2).

Relative Amount: Connecticut/Rhode

Island contribute 35 percent of the total

manmade ppb >= 125 ppb in Western

Massachusetts (CAMx Metric 4; 4-

episode average percent contribution).

—Georgia’s Contribution to 1-Hour

Nonattainment in Birmingham

Magnitude of Contribution: The

maximum contribution is 51 ppb

(CAMx Metric 2); the highest daily

average contribution is 24 ppb (CAMx

Metric 3).

Frequency of Contribution: Georgia

contributes at least 10 ppb to 11 percent

of the 1-hr exceedences (UAM–V

Metrics 1 and 2).

Relative Amount: The total

contribution from Georgia is equivalent

to 12 percent of the total amount >=125

ppb in Birmingham (UAM–V Metric 3);

Georgia contributes 3 percent of the

total manmade ppb >= 125 ppb in

Birmingham (CAMx Metric 4; 4-episode

average percent contribution).

—Illinois’s Contribution to 1-Hour

Nonattainment in New York City

Magnitude of Contribution: The

maximum contribution is 8 ppb (CAMx

Metric 2); the highest daily average

contribution is 6 ppb (CAMx Metric 3).

Frequency of Contribution: Illinois

contributes at least 5 ppb to 20 percent

of the 1-hr exceedences (CAMx Metrics

1 and 2).

Relative Amount: The total

contribution from Illinois is equivalent

to 3 percent of the total amount >=125

ppb in New York City (UAM–V Metric

3); Illinois contributes 3 percent of the

total manmade ppb >= 125 ppb in New

York City (CAMx Metric 4; single

highest episode percent contribution).

—Indiana’s Contribution to 1-Hour

Nonattainment in Baltimore

Magnitude of Contribution: The

maximum contribution is 8 ppb (CAMx

Metric 2); the highest daily average

contribution is 6 ppb (CAMx Metric 3).

Frequency of Contribution: Indiana

contributes at least 5 ppb to 26 percent

of the 1-hr exceedences (CAMx Metrics

1 and 2).

Relative Amount: The total

contribution from Indiana is equivalent

to 4 percent of the total amount >=125

ppb in Baltimore (UAM–V Metric 3);

Indiana contributes 3 percent of the

total manmade ppb >= 125 ppb in New

York City (CAMx Metric 4; single

highest episode percent contribution).

—Kentucky’s Contribution to 1–Hour

Nonattainment in Baltimore

Magnitude of Contribution: The

maximum contribution is 9 ppb (CAMx

Metric 2); the highest daily average

contribution is 8 ppb (CAMx Metric 3).

Frequency of Contribution: Kentucky

contributes at least 5 ppb to 24 percent

of the 1-hr exceedences (CAMx Metrics

1 and 2).

Relative Amount: The total

contribution from Kentucky is

equivalent to 3 percent of the total

amount >=125 ppb in Baltimore (UAM–

V Metric 3); Kentucky contributes 5

percent of the total manmade ppb >=

125 ppb in Baltimore (CAMx Metric 4;

single highest episode percent

contribution).

—Maryland/District of Columbia/

Delaware’s Contribution to 1-Hour

Nonattainment in New York City

Magnitude of Contribution: The

maximum contribution is 50 ppb

(CAMx Metric 2); the highest daily

average contribution is 15 ppb (CAMx

Metric 3).

Frequency of Contribution: Maryland/

District of Columbia/Delaware

contribute at least 10 ppb to 14 percent

of the 1-hr exceedences and at least 5

ppb to 38 percent of the 1-hr

exceedences (CAMx Metrics 1 and 2).

Relative Amount: Maryland/District

of Columbia/Delaware contribute 5

percent of the total manmade ppb >=

125 ppb in New York City (CAMx

Metric 4; 4-episode average percent

contribution).

—Massachusetts’ Contribution to 1-

Hour Nonattainment in Portland, ME

Magnitude of Contribution: The

maximum contribution is 79 ppb

(CAMx Metric 2); the highest daily

average contribution is 67 ppb (CAMx

Metric 3).

Frequency of Contribution:

Massachusetts contributes at least 10

ppb to 100 percent of the 1-hr

exceedences (UAM–V Metrics 1 and 2).

Relative Amount: The total

contribution from Massachusetts is

equivalent to 100 percent of the total

amount >=125 ppb in Portland, ME
Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations 57397

(UAM–V Metric 3); Massachusetts

contributes 56 percent of the total

manmade ppb >= 125 ppb in Portland,

ME (CAMx Metric 4; 4-episode average

percent contribution).

—Michigan’s Contribution to 1-Hour

Nonattainment in Baltimore

Magnitude of Contribution: The

maximum contribution is 9 ppb (CAMx

Metric 2); the highest daily average

contribution is 8 ppb (CAMx Metric 3).

Frequency of Contribution: Michigan

contributes at least 5 ppb to 7 percent

of the 1-hr exceedences (CAMx Metrics

1 and 2).

Relative Amount: The total

contribution from Michigan is

equivalent to 5 percent of the total

amount >=125 ppb in Baltimore (UAM–

V Metric 3); Michigan contributes 5

percent of the total manmade ppb >=

125 ppb in Baltimore (CAMx Metric 4;

single highest episode percent

contribution).

—Missouri’s Contribution to 1-Hour

Nonattainment over Lake Michigan

Magnitude of Contribution: The

maximum contribution is 19 ppb

(CAMx Metric 2); the highest daily

average contribution is 12 ppb (CAMx

Metric 3).

Frequency of Contribution: Missouri

contributes at least 10 ppb to 66 percent

of the 1-hr exceedences (CAMx Metrics

1 and 2).

Relative Amount: The total

contribution from Missouri is equivalent

to 22 percent of the total amount >=125

ppb over Lake Michigan (UAM–V

Metric 3); Missouri contributes 9

percent of the total manmade ppb >=

125 ppb over Lake Michigan (CAMx

Metric 4; 4-episode average percent

contribution).

—New Jersey’s Contribution to 1-Hour

Nonattainment in Western

Massachusetts

Magnitude of Contribution: The

maximum contribution is 30 ppb

(CAMx Metric 2); the highest daily

average contribution is 23 ppb (CAMx

Metric 3).

Frequency of Contribution: New

Jersey contributes at least 10 ppb to 100

percent of the 1-hr exceedences (CAMx

Metrics 1 and 2).

Relative Amount: New Jersey

contributes 16 percent of the total

manmade ppb >= 125 ppb in Western

Massachusetts (CAMx Metric 4; 4-

episode average percent contribution).

—New York’s Contribution to 1-Hour

Nonattainment in Western

Massachusetts

Magnitude of Contribution: The

maximum contribution is 25 ppb

(CAMx Metric 2); the highest daily

average contribution is 23 ppb (CAMx

Metric 3).

Frequency of Contribution: New York

contributes at least 10 ppb to 100

percent of the 1-hr exceedences (CAMx

Metrics 1 and 2).

Relative Amount: New York

contributes 18 percent of the total

manmade ppb >= 125 ppb in Western

Massachusetts (CAMx Metric 4; 4-

episode average percent contribution).

—North Carolina’s Contribution to 1-

Hour Nonattainment in Philadelphia

Magnitude of Contribution: The

maximum contribution is 10 ppb

(CAMx Metric 2); the highest daily

average contribution is 9 ppb (CAMx

Metric 3).

Frequency of Contribution: North

Carolina contributes at least 2 ppb to 4

percent of the 1-hr exceedences (UAM–

V Metrics 1 and 2).

Relative Amount: The total

contribution from North Carolina is

equivalent to 4 percent of the total

amount >=125 ppb in Philadelphia

(UAM–V Metric 3); North Carolina

contributes 2 percent of the total

manmade ppb >= 125 ppb in

Philadelphia (CAMx Metric 4; single

highest episode percent contribution).

—Ohio’s Contribution to 1-Hour

Nonattainment in Baltimore

Magnitude of Contribution: The

maximum contribution is 13 ppb

(CAMx Metric 2); the highest daily

average contribution is 12 ppb (CAMx

Metric 3).

Frequency of Contribution: Ohio

contributes at least 5 ppb to 51 percent

of the 1-hr exceedences (CAMx Metrics

1 and 2).

Relative Amount: The total

contribution from Ohio is equivalent to

11 percent of the total amount >=125

ppb in Baltimore (UAM–V Metric 3);

Ohio contributes 4 percent of the total

manmade ppb >= 125 ppb in Baltimore

(CAMx Metric 4; 4-episode average

percent contribution).

—Pennsylvania’s Contribution to 1-

Hour Nonattainment in Greater

Connecticut

Magnitude of Contribution: The

maximum contribution is 28 ppb

(CAMx Metric 2); the highest daily

average contribution is 23 ppb (CAMx

Metric 3).

Frequency of Contribution:

Pennsylvania contributes at least 10 ppb

to 60 percent of the 1-hr exceedences

and at least 5 ppb to 98 percent of the

1-hr exceedences (CAMx Metrics 1 and

2).

Relative Amount: Pennsylvania

contributes 10 percent of the total

manmade ppb >= 125 ppb in Greater

Connecticut (CAMx Metric 4; 4-episode

average percent contribution).

—South Carolina’s Contribution to 1-

Hour Nonattainment in Atlanta

Magnitude of Contribution: The

maximum contribution is 24 ppb

(CAMx Metric 2); the highest daily

average contribution is 23 ppb (CAMx

Metric 3).

Frequency of Contribution: South

Carolina contributes at least 5 ppb to 6

percent of the 1-hr exceedences (UAM–

V Metrics 1 and 2).

Relative Amount: The total

contribution from South Carolina is

equivalent to 4 percent of the total

amount >=125 ppb in Atlanta (UAM–V

Metric 3); South Carolina contributes 2

percent of the total manmade ppb >=

125 ppb in Atlanta (CAMx Metric 4;

single highest episode percent

contribution).

—Tennessee’s Contribution to 1–Hour

Nonattainment Over Lake Michigan

Magnitude of Contribution: The

maximum contribution is 12 ppb

(CAMx Metric 2); the highest daily

average contribution is 11 ppb (CAMx

Metric 3).

Frequency of Contribution: Tennessee

contributes at least 5 ppb to 14 percent

of the 1-hr exceedences (UAM–V

Metrics 1 and 2).

Relative Amount: The total

contribution from Tennessee is

equivalent to 6 percent of the total

amount >=125 ppb over Lake Michigan

(UAM–V Metric 3); Tennessee

contributes 10 percent of the total

manmade ppb >= 125 ppb over Lake

Michigan (CAMx Metric 4; single

highest episode percent contribution).

—Virginia’s Contribution to 1-Hour

Nonattainment in New York City

Magnitude of Contribution: The

maximum contribution is 25 ppb

(CAMx Metric 2); the highest daily

average contribution is 11 ppb (CAMx

Metric 3).

Frequency of Contribution: Virginia

contributes at least 10 ppb to 11 percent

of the 1-hr exceedences and at least 5

ppb to 36 percent of the 1-hr

exceedences (CAMx Metrics 1 and 2).

Relative Amount: The total

contribution from Virginia is equivalent

to 11 percent of the total amount >=125

ppb in New York City (UAM–V Metric

3); Virginia contributes 4 percent of the
57398 Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations

50See ‘‘Notice of Availability’’ 63 FR 45032

(August 24, 1998).

total manmade ppb >= 125 ppb in New

York City (CAMx Metric 4; 4-episode

average percent contribution).

—West Virginia’s Contribution to 1-

Hour Nonattainment in New York City

Magnitude of Contribution: The

maximum contribution is 14 ppb

(CAMx Metric 2); the highest daily

average contribution is 10 ppb (CAMx

Metric 3).

Frequency of Contribution: West

Virginia contributes at least 5 ppb to 9

percent of the 1-hr exceedences and at

least 2 ppb to 28 percent of the 1-hr

exceedences (UAM–V Metrics 1 and 2).

Relative Amount: The total

contribution from West Virginia is

equivalent to 9 percent of the total

amount >=125 ppb in New York City

(UAM–V Metric 3); West Virginia

contributes 7 percent of the total

manmade ppb >= 125 ppb in New York

City (CAMx Metric 4; single highest

episode percent contribution).

—Wisconsin’s Contribution to 1–Hour

Nonattainment Over Lake Michigan

Magnitude of Contribution: The

maximum contribution is 43 ppb

(CAMx Metric 2); the highest daily

average contribution is 8 ppb (CAMx

Metric 3).

Frequency of Contribution: Wisconsin

contributes at least 10 ppb to 11 percent

of the 1-hr exceedences (CAMx Metrics

1 and 2).

Relative Amount: Wisconsin

contributes 4 percent of the total

manmade ppb >= 125 ppb over Lake

Michigan (CAMx Metric 4; 4-episode

average percent contribution).

d. Conclusions From Air Quality

Evaluation of Downwind Contributions.

As indicated above, EPA is following a

multi-step approach for determining

whether emissions from an upwind

State significantly contribute to

nonattainment downwind. The first step

involves an air quality evaluation to

determine whether the air quality

factors, and particularly the extent of

the downwind contributions from

emissions in the upwind State, indicate

that those contributions are large and/or

frequent enough to be of concern under

the 1-hour and/or 8-hour NAAQS. The

second step, as described below,

employs a cost-effectiveness analysis to

determine which of the upwind

emissions may be eliminated through

highly cost-effective controls. Any

emissions that may be so eliminated are

considered to be emissions that

significantly contribute to

nonattainment downwind. Finally, to

confirm that the emissions considered

to significantly contribute, taken as a

whole, have a meaningful impact on

nonattainment in downwind areas, EPA

modeled the air quality effects of

eliminating that amount of emissions

(see Section IV, Air Quality Assessment,

below).

The EPA’s conclusions from the first

step in this process, the air quality

evaluation, is that emissions from

sources in each of the 23 jurisdictions

listed below make a significant

contribution to nonattainment

downwind for both the 1-hour and 8-

hour NAAQS and interfere with

maintenance of the 8-hour NAAQS.

This determination was based on two

independent sets of analyses, each of

which EPA believes provides an

independent basis for these conclusions.

These two independent analyses are (1)

subregional modeling using UAM–V,

and (2) State-by-State modeling using

CAMx and UAM–V. For the subregional

modeling, EPA examined the frequency

and magnitude of the impacts from each

subregion along with State emissions

data and other air quality information to

evaluate the contributions from upwind

States to nonattainment in downwind

areas. For the UAM–V and CAMx Stateby-State techniques, a number of

measures of ozone contribution, or

metrics, were used to assess, from

several perspectives, the air quality

effect of contributions from sources in

different upwind States.

The EPA weighed the results of its

analysis of these several air quality

metrics to determine which upwind

States contain sources whose emissions

contribute significantly to downwind

nonattainment or maintenance

problems. By examining the results of

several air quality metrics, EPA assured

that no one metric determined whether

a State contains sources whose

emissions contribute to downwind air

quality problems. Rather, the

determination of whether an upwind

State contained sources whose

emissions contribute significantly to a

downwind nonattainment problem was

based on the extent of the contributions

reflected by multiple metrics. The EPA

concluded that each set of modeling

(i.e., subregional and State-by-State)

when considered independently under

EPA’s weight-of-evidence approach

provides a sound technical basis for

finding that NOX emissions from

sources in the following 23 jurisdictions

make a significant contribution to

nonattainment of the 1-hour and 8-hour

NAAQS in, or interfere with

maintenance of the 8-hour NAAQS by,

one or more downwind States:

Alabama

Connecticut

Delaware

District of Columbia

Georgia

Illinois

Indiana

Kentucky

Maryland

Massachusetts

Michigan

Missouri

New Jersey

New York

North Carolina

Ohio

Pennsylvania

Rhode Island

South Carolina

Tennessee

Virginia

West Virginia

Wisconsin

The remaining 15 OTAG States not

covered by this final rule are discussed

below.

5. States Not Covered by This

Rulemaking

In Section VI of the NPR, EPA

proposed to find that emissions from

sources in the following 15 States in the

OTAG region do not significantly

contribute to downwind nonattainment

under the 1-hour or 8-hour ozone

NAAQS, or interfere with maintenance

under the 8-hour NAAQS: Arkansas,

Florida, Iowa, Kansas, Louisiana, Maine,

Minnesota, Mississippi, North Dakota,

Nebraska, New Hampshire, Oklahoma,

South Dakota, Texas, Vermont (62 FR

60369). The EPA received comments on

this section of the NPR and has recently

conducted some additional CAMx

analyses.50 The CAMx modeling

suggested that further analysis using

UAM–V State-by-State modeling would

be warranted in order to have a set of

information comparable to that for other

States that are subject to this rule. In

today’s rulemaking, EPA is taking no

action on whether emissions from

sources in these 15 States do or do not

contribute significantly to downwind

nonattainment, or interfere with

maintenance downwind, under either

NAAQS. Thus, by today’s rulemaking,

EPA is not requiring these 15 States to

submit SIP revisions providing for NOX

emissions controls to meet a statewide

NOX emissions budget; nor is EPA

determining that these States will not be

required to make these SIP submissions

in the future. The EPA is continuing to

review available information on the

downwind impacts of these States,

including comments submitted on the

NPR. In addition, EPA plans to conduct

State-by-State modeling to determine

whether a SIP revision under section

110(a)(2)(D)(i)(I) should be required

from any of these States in the future.
Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations 57399

51OTAG Recommendation: Utility NOX Controls,

approved by the Policy Group, June 3, 1997.

The EPA intends to begin this modeling

in the fall of 1998.

As discussed in the NPR (62 FR 60318

at 60370), EPA reiterates that these 15

States may need to cooperate and

coordinate SIP development activities

with other States that are subject to

today’s action. Also, States with

interstate nonattainment areas for the 1-

hour standard and/or the new 8-hour

standard should cooperate in reducing

emissions to mitigate local-scale

interstate transport problems (e.g.,

transport from one State in a multi-state

urban nonattainment area to another

State in that area) to provide for

attainment in the nonattainment area as

a whole. The EPA encourages the 15

States to conduct additional analyses on

ozone transport recommended by the

OTAG Policy Group, which indicated

that these States, ‘‘* * * will, in

cooperation with EPA, periodically

review their emissions, and the impact

of increases, on downwind

nonattainment areas and, as

appropriate, take steps necessary to

reduce such impacts including

appropriate control measures.’’ 51

Comment: A number of commenters

supported the proposal to exclude the

proposed States, either in general or for

specific States. Others opposed the

proposal in general, or for specific

States.

Response: Because EPA is taking no

action on the 15 States at this time, EPA

will not respond to comments

concerning these States at this time. As

discussed above, EPA intends to

continue to review ambient air quality

data, air quality modeling results, and

other technical information on the

downwind contribution from all States

not found to be significant contributors

in today’s action.

Comment: Several commenters stated

that if EPA revisits which States should

be included in the rulemaking, EPA

must reopen the public comment

period.

Response: The EPA agrees. Because

today’s action does not propose a

change from the NPR concerning which

States should be covered, no new

comment period is needed at this time.

As EPA noted in the NPR, if results from

additional modeling and technical

analyses indicate that States other than

the 22 States (and the District of

Columbia) that are the subject of today’s

action should be required to submit a

SIP revision under section

110(a)(2)(D)(i)(I), EPA will publish a

new NPR as to any such States and

provide an additional comment period.

As also stated in the NPR, in 2007, EPA

will reassess transport in the full OTAG

region to evaluate the effectiveness of

the regional NOX measures and the

need, if any, for additional regional

controls.

D. Cost Effectiveness of Emissions

Reductions

As discussed above, in today’s action,

EPA considers control costs in

determining whether, and the extent to

which, upwind emissions contribute

significantly to nonattainment, or

interfere with maintenance downwind.

The EPA considers cost factors in

conjunction with other factors generally

related to levels of emissions.

1. Sources Included In the CostEffectiveness Determination

This subsection describes the

rationale used to determine the cost

effectiveness of emissions reductions

measures. The EPA evaluates the

relative costs of the available control

measures using average cost

effectiveness, measured as dollars per

ton of NOX reduced relative to a

baseline, to identify those emissions

reductions that are ‘‘highly costeffective.’’ In performing this

evaluation, EPA considers the cost

savings of a regionwide NOX emissions

trading system for large electricity

generating boilers and turbines (i.e.,

boilers and turbines serving a generator

larger than 25 MWe). As described in

this section, EPA has determined that

these emissions reductions are highly

cost effective on a regionwide basis.

To assure equity among the various

source categories and the industries

they represent, EPA considered the cost

effectiveness of controls for each source

category separately throughout the SIP

call region. Sources are combined into

a common source category if they serve

the same general industry (e.g., boilers

and turbines that are used by the

electricity generation industry are

combined in the same category). In

general, this means that the sources in

the same source category share the same

six-digit source code classification

(SCC). One exception is in the case of

boilers and turbines which are

combined and then separated into (1) a

category of boilers and turbines serving

generators that produce electricity for

sale to the grid; or (2) a category of

boilers and turbines that exclusively

generate steam and/or mechanical work

(e.g., provide energy to an industrial

pump), or produce electricity primarily

for internal use and not for sale. The

EPA believes that this categorization

better reflects the industrial sectors

served.

For each source category, the required

emission levels (in tons per ozone

season) were determined based on the

application of NOX controls that achieve

the greatest feasible emissions reduction

while still falling within a cost-per-tonreduced range that EPA considers to be

highly cost-effective (hereinafter also

referred to as ‘‘highly cost-effective’’

measures). Marginal or incremental

costs of control are additional costeffective measures that may provide

important information about

alternatives. In particular, incremental

cost-effectiveness helps to identify

whether a more stringent control option

imposes much higher costs relative to

the average cost per ton for further

control. The use of an average costeffectiveness measure may not fully

reveal costly incremental requirements

where control options achieve large

reductions in emissions (relative to the

baseline).

In this rulemaking, EPA has chosen to

focus on an average cost-effectiveness

measure in identifying highly costeffective control options for several

reasons. Since EPA’s determination for

the core group of sources is based on the

adoption of a broad-based trading

program, average cost-effectiveness

serves as an adequate measure across

sources because sources with high

marginal costs will be able to take

advantage of this program to lower their

costs. In addition, average costeffectiveness estimates are readily

available for other recently adopted

NOX control measures.

The EPA examined a representative

sample of potentially available controls.

NOX controls for this rulemaking were

considered highly cost-effective for the

purposes of reducing ozone transport to

the extent they achieve the greatest

feasible emissions reduction but still

cost no more than $2,000 per ton of

ozone season NOX emissions removed

(in 1990 dollars), on average, for each

source category. The discussion below

further describes the basis for this cost

amount and the techniques used for

each category. Many may consider

certain controls that cost more than

$2,000 per ton of NOX reduced to be

reasonably cost-effective in reducing

ozone transport or in achieving

attainment with the ozone NAAQS in

specific nonattainment areas; however,

EPA has determined to focus today’s

rulemaking on only highly cost-effective

reductions. In the future, as EPA

continues to consider the impact of

ozone transport and the most effective

ways to assure downwind attainment,

EPA may reconsider whether State NOX

budget levels should be lowered to

reflect application of additional controls
57400 Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations

that, although more expensive, are

nevertheless cost-effective. In addition,

as discussed below, in determining

whether to assume reductions from

source categories with only a few

sources or relatively small emissions,

EPA considered administrative

efficiency in developing conclusions

about whether to assume emissions

reductions for these sources.

In determining the cost of NOX

reductions by large electricity

generating units (EGUs), EPA assumed

an emissions trading system. As

discussed in Section IV below, EPA

evaluated and compared the likely air

quality impacts of this rulemaking with

and without a regionwide NOX

emissions trading system for electricity

generating sources. This analysis shows

that a regionwide trading program

causes no significant adverse air quality

impacts. Because such a program would

result in significant cost savings, EPA’s

cost-effectiveness determination for

large electricity generating boilers and

turbines assumes that each State will

adopt the lowest cost approach, i.e., the

States will elect to include these sources

in a regionwide NOX emissions trading

program. However, States retain the

option of choosing other, perhaps more

expensive, approaches to achieving the

necessary reductions. For non-EGU

sources in the core group of the trading

program, EPA used a least cost method

which is equivalent to an assumption of

an intrastate trading program. Inclusion

of these sources in a regionwide trading

program would provide further cost

savings. For other source categories for

which EPA identified highly costeffective controls (i.e., internal

combustion engines and cement

manufacturing), EPA assumed sourcespecific controls. However, a State may

choose to include such categories in the

trading program and realize further cost

savings.

For the purposes of this rulemaking,

EPA considers the following sizes of

point sources to be large: (1) electricity

generating boilers and turbines serving

a generator greater than 25 MWe; or (2)

other point sources with a heat input

greater than 250 mmBtu/hr or which

emit more than one ton of NOX per

average summer day.

In the NPR, EPA based the costeffectiveness determination on NOX

emissions controls that are available and

of comparable cost to other recently

undertaken or planned NOX measures.

Table 1 provides a reference list of

measures that EPA and States have

recently undertaken to reduce NOX and

their average annual costs per ton of

NOX reduced. Most of these measures

fall below $2,000 per ton. With few

exceptions, the average costeffectiveness of these measures is

representative of the average costeffectiveness of the types of controls

EPA and States have needed to adopt

most recently because their previous

planning efforts have already taken

advantage of opportunities for even

cheaper controls. The EPA believes that

the cost-effectiveness of measures that

EPA or States have adopted, or

proposed to adopt, forms a good

reference point for determining which

of the available additional NOX control

measures can most easily be

implemented by upwind States whose

emissions impact downwind

nonattainment problems.

TABLE 1.—AVERAGE COST-EFFECTIVENESS OF NOX CONTROL MEASURES RECENTLY UNDERTAKEN

[1990 dollars]

Control measure Cost per ton of

NOX Removed

NOX RACT ......................................................................................................................................................................................... 150–1,300

Phase II Reformulated Gasoline ........................................................................................................................................................ 52 4,100

State Implementation of the Ozone Transport Commission Memorandum of Understanding ......................................................... 950–1,600

New Source Performance Standards for Fossil Steam Electric Generation Units ........................................................................... 1,290

New Source Performance Standards for Industrial Boilers ............................................................................................................... 1,790

52Average cost representing the midpoint of $2,180 to $6,000 per ton. This cost represents the projected additional cost of complying with the

Phase II RFG NOX standards, beyond the cost of complying with the other standards for Phase II RFG.

The Federal Phase II RFG costs

presented in Table 1 are not strictly

comparable to the other costs cited in

the table. Federal Phase II RFG will

provide large VOC reductions in

addition to NOX reductions. Federal

RFG is required in nine cities with the

nation’s worst ozone nonattainment

problems; other nonattainment areas

have chosen to opt into the program as

part of their attainment strategy. The

mandated areas and those areas in the

OTAG region that have chosen to opt

into the program are areas where

significant local reductions in ozone

precursors are needed; such areas may

value RFG’s NOX and VOC reductions

differently for their local ozone benefits

than they would value NOX reductions

from RFG or other programs for ozone

transport benefits.

Commenters on the proposal

generally agreed with basing the costeffectiveness determination on the cost

effectiveness of other recently

undertaken measures. Therefore, EPA

has considered controls with an average

cost-effectiveness less than $2,000 per

ton of NOX removed to be highly cost

effective and has calculated the amounts

of emissions that States must prohibit

based on application of these controls.

Some commenters believed that a more

appropriate measure of cost

effectiveness was incremental—instead

of average—dollars per ton of NOX

removed. Other commenters believed

that a more appropriate measure was

dollars per ppb of ozone removed from

a nonattainment area. The EPA

continues to depend on regionwide

average dollars per ton of NOX removed

when evaluating what control measures

are highly cost-effective for the purposes

of this rulemaking.

Table 2 summarizes the control

options investigated for each source

category and the resulting average,

regionwide cost effectiveness.
Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations 57401

55For reasons explained in Section V., below,

EPA has determined that May 1, 2003 is the earliest

practicable date for achieving the level of emissions

reductions EPA selected, and therefore is the

appropriate date for achieving these reductions in

light of the CAA’s attainment date requirements.

TABLE 2.—AVERAGE COST EFFECTIVENESS OF OPTIONS ANALYZED 53

[1990 dollars in 2007]

Source category

Average Cost-effectiveness ($/ozone season ton) for each

control option

Boilers and Turbines Generating Electricity .......................................................... 0.20 lb/mmBtu ...... 0.15 lb/mmBtu ...... 0.12 lb/mmBtu.

$1,263 ................... $1,468 ................... $1,760.

Boilers and Turbines not Generating Electricity .................................................... 50% reduction ....... 60% reduction ....... 70% reduction.

$1,235 ................... $1,467 ................... $2,140.

Other Stationary Sources 54 ................................................................................... $3,000/ton maximum per source.$4,000/ton maximum per source.$5,000/ton maximum per source.

Cement Manufacturing ........................................................................................... $1,458 ................... $1,458 ................... $1,458

Glass Manufacturing .............................................................................................. $2,020 ................... $2,339 ................... $4,758.

Incinerators ............................................................................................................ $2,118 ................... $2,118 ................... $2,118.

Internal Combustion Engines ................................................................................. $1,213 ................... $1,213 ................... $1,215.

Process Heaters .................................................................................................... $2,860 ................... $2,896 ................... $2,896.

53The cost-effectiveness values in Table 2 are regionwide averages. The cost-effectiveness values represent reductions beyond those required by Title IV or Title I RACT, where applicable. 54For cement manufacturing, incinerators, internal combustion engines and process heaters, the table indicates that the same control technology (at the same cost) would be selected whether the cost ceiling for each source is $3,000, $4,000, or $5,000 per ton; thus the average

cost-effectiveness number for these source categories is the same in each column. For glass manufacturing, the table indicates that additional

emissions reductions would be obtained from more effective and more costly control technologies as the cost ceiling increase.

The following discussion explains the

controls determined by EPA to be highly

cost-effective for each source category.

The EPA has analyzed the

implications of each State limiting

trading within its borders compared to

entering into a common trading program

with all other States, provided that

States choose to control EGUs at an

average level of 0.15 lb/mmBtu. In the

case of intrastate trading, EPA found

that the average cost per ton of the

resulting ozone season NOX reduction

was about $1,499 per ton. This result

from the IPM model was for all the

States together considering changes in

dispatch and other aspects of the future

operation of the nation’s power system.

Individual State results were not

provided by the model. As explained

below, EPA expects that individual

State cost per ton results are likely to be

fairly close to this collective result.

For a regionwide budget based on

0.15 lb/mmBtu, EPA’s analyses suggest

that whether (1) there were individual

State trading programs, or (2) a single

regionwide trading program, all States

experienced a substantial reduction in

summer NOX emissions from Base Case

emissions levels. For this to occur, there

have to be similar opportunities

throughout the SIP call region for highly

cost-effective reductions to occur at

EGUs. If this were not true, EPA would

have found, in the case where there is

a single trading program across the

entire SIP call region, that some States

reduce a much greater share of their

NOX emissions than other States do.

The fact that there are similar

opportunities for NOX reductions in

each of the States indicates that if there

were individual State trading programs

in place they would each generally have

an average cost effectiveness for

reducing ozone season NOX emissions

that is fairly close to the cost

effectiveness of trading programs in

other States. Therefore, each State is

generally likely to have an average cost

effectiveness of about $1,550 per ton,

the amount we found in the results of

the IPM model run for a scenario where

each State ran its own trading program.

a. Electricity Generating Boilers and

Turbines. For EGUs larger than 25 MWe,

the control level was determined by

applying a uniform NOX emissions rate

regionwide. The cost-effectiveness for

each control level was determined using

the IPM. Details regarding the

methodologies used can be found in the

Regulatory Impact Analysis of this

rulemaking. Table 2 summarizes the

control levels and resulting costeffectiveness of three options analyzed.

A regionwide level of 0.20 lb/mmBtu

was rejected because though it resulted

in an average cost effectiveness of less

than $2,000 per ton, the air quality

benefits were less than those for the 0.15

lb/mmBtu level which was also less

than $2,000 per ton. The results suggest

that a regionwide level of 0.15 lb/

mmBtu should be assumed for this

source category when calculating the

amount of emissions that should be

considered significant and therefore

prohibited in each covered State. This

control level has an average costeffectiveness of $1,468 per ozone season

ton removed. This amount is consistent

with the range for cost-effectiveness that

EPA has derived from recently adopted

(or proposed to be adopted) control

measures. As discussed later in this

preamble, EPA has determined that EGU

sources are fully capable of

implementing this level of control by

May 1, 2003.

The EPA estimates that a control level

based on 0.12 lb/mmBtu, has a cost

effectiveness of $1,760 per ozone season

ton removed, which is within the upper

range of cost effectiveness. This estimate

is based on the Agency’s best estimates

of several key assumptions on the

performance of pollution control

technologies and electricity generation

requirements in the future which the

Agency thoroughly researched over the

last two years. Given that the cost per

ton estimate for 0.12 lb/mmBtu trading

is much closer to $2,000 than the 0.15

lb/mmBtu trading, EPA is not as

confident about the robustness of the

results. Also, although EPA is very

comfortable that a 0.15 lb/mmBtu

trading program beginning in 2003 will

not lead to installation of SCR

technology at a level and in a manner

that will be difficult to implement or

result in reliability problems for electric

power generation, the Agency’s level of

comfort is not as high in considering

0.12 lb/mmBtu-based trading.55 With a

strong need to implement a program by

2003 that is recognized by the States as

practical, necessary, and broadly

accepted as highly cost effective, the

Agency has decided to base the
57402 Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations

emissions budgets for EGUs on a 0.15

lb/mmBtu trading level of control.

It should be noted that the costeffectiveness values for EGUs were

calculated using a slightly older version

of the final EGU inventory. Changes

made to the inventory and growth

assumptions resulted in decreasing the

final regionwide allowable emission

level for EGUs, under the 0.15 option,

to 543,825 tons per year from 563,785

tons per year. Reducing the allowable

regionwide emissions increased the

average cost-effectiveness value of the

0.15 option from $1,468/ton, to $1,503/

ton.

b. Other Stationary Sources. The

appropriate cost-effective control level

for large non-EGU source categories was

determined by evaluating various

regulatory alternatives. For industrial

boilers and turbines (i.e., boilers and

turbines greater than 250 mm/Btu per

hour or with NOX emissions greater

than 1 tpd), the control level was

determined by applying a uniform

percent reduction regionwide in

increments of 10 percent. For all other

stationary sources, the control level was

determined by applying sourcecategory-specific cost-effectiveness

thresholds, because trading was not

assumed to be readily available for these

source categories. Details regarding the

methodologies used are in the

Regulatory Impact Analysis. Table 2

summarizes the control levels and

resulting cost-effectiveness for each

option under each category.

Further, for large non-EGUs, the costeffectiveness determination includes

estimates of the additional emissions

monitoring costs that sources would

incur in order to participate in a trading

program. Some non-EGUs already

monitor their emissions. In the NPR,

EPA had not included monitoring costs

in the cost-effectiveness determination

because such costs had not been

estimated at that time. Since then, EPA

has evaluated monitoring system costs.

These costs are defined in terms of

dollars per ton of NOX removed so that

they can be combined with the costeffectiveness figures related to control

costs. Since monitoring costs do not

vary with the level of control, the cost

per ton for monitoring varies in

accordance with the amount of control

being required. For purposes of this

analysis, the level of control was

assumed to be the level of control used

to calculate the budget. Monitoring costs

varied from about $150 to $400 per ton

of NOX removed, depending on the type

of source category.

The EPA, therefore, determines that:

(1) For large non-electricity-generating

industrial boilers and turbines, a control

level corresponding to 60 percent

reduction from baseline levels is highly

cost-effective (this percent reduction

corresponds to a regionwide control

level of about 0.17 lb/mmBtu); and (2)

for large internal combustion engines

and cement manufacturing sources, a

control level corresponding to the

application of NOX reduction

technology costing no more than

$5,000/ton for each source is, on

average, highly cost effective. As

indicated in Table 2 and described in

detail in the RIA, these control levels

are associated with a cost effectiveness

of approximately $1,467/ton for boilers

and turbines, $1,458/ton for cement

manufacturing, and $1,215/ton for

internal combustion engines. This

results in an average emissions

reduction from uncontrolled emissions

of 90 percent for internal combustion

engines and 30 percent for cement

manufacturing sources. The EPA notes

that States may include these source

categories in the model NOX budget

trading program, further assuring that

each source would be able to costeffectively meet its reduction

requirements. The EPA determined that

controlling glass manufacturing sources,

incinerators, and process heaters was

not highly cost-effective because all the

options analyzed for these source

categories cost more than $2,000 per ton

of NOX removed. Thus, no additional

controls are assumed for these sources

when determining the significant

amounts that must be reduced in each

State.

2. Sources Not Included In the Costeffectiveness Determination

For the following groups of sources,

EPA is determining that no additional

control measures or levels of control

should be assumed in this rulemaking,

for the reasons described.

a. Area Sources. In the NPR, EPA

noted that control levels for area sources

(i.e., sources other than mobile or point

sources) could not be determined based

on available information concerning

applicable control technologies.

Comments to the NPR did not identify

specific NOX control technologies that

were both technologically feasible and

highly cost-effective. Because EPA has

no new information on applicable

control technologies for area sources, no

additional control level is assumed for

these sources in this rulemaking.

Further discussion concerning area

sources can be found in Section III,

below, of this preamble.

b. Small Point Sources. For the

purposes of this rulemaking, EPA

considers the following sizes of point

sources to be small: (1) Electricity

generating boilers and turbines serving

a generator 25 MWe or less, and (2)

other point sources with a heat input of

250 mmBtu/hr or less and which emit

less than one ton of NOX per average

summer day. In the NPR, EPA stated

that the collective emissions from small

sources were relatively small (in the

context of this rulemaking) and the

administrative burden, to the States and

regulated entities, of controlling such

sources was likely to be considerable.

As a result, in the NPR, EPA proposed

not to assume reductions from these

sources in establishing the State

budgets.

Comments to the NPR did not identify

specific approaches that would result in

significant emission reductions and be

administratively efficient in controlling

these sources. On the contrary, many

comments encouraged EPA to exclude

small point sources from any budget

calculations for this rulemaking.

Therefore, in today’s action, EPA is

not assuming additional control levels

for these sources. Further discussion

concerning small point sources may be

found in section III, below, of this

preamble.

c. Mobile Sources. In the NPR, EPA

noted that it could not identify any

additional NOX controls that States

could implement for mobile or nonroad

sources beyond those already reflected

in the proposed State NOX budgets that

were both technologically feasible and

cost-effective, relative to point sources

covered by this rule, for the purposes of

reducing NOX. Several commenters

stated that the EPA should require

States to implement additional

reductions for mobile sources. However,

these commenters did not identify

specific, new, technologically feasible

mobile source NOX controls that were

highly cost-effective by the standards of

today’s action. The EPA has reexamined the availability of mobile

source control measures available to

States, as discussed in more detail in

sections III.D. and III.E. below, and has

not identified any such controls that are

both technologically feasible and highly

cost-effective for NOX control.

Therefore, the States’ final NOX budgets

promulgated in today’s action do not

assume implementation of additional

highway or nonroad mobile source

controls or expansion of existing

controls beyond those described in the

NPR. Further discussion concerning

mobile sources, including the national

measures EPA has assumed for purposes

of today’s rule, can be found in Section

III, Determination of Budgets.

d. Other stationary sources. The EPA

does not assume, in this rulemaking,

any additional control measures or
Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations 57403

56As described elsewhere, the controls

specifically required under the CAA include the

controls identified in the modeling baseline, as well

as certain Federal controls such as NLEV. These

controls do not include any additional reductions

that may be required in the local nonattainment

areas as part of their attainment demonstrations.

lower emissions levels for municipal

waste combustors because these

combustors are already being controlled

through MACT regulations. Moreover,

no additional control measures were

assumed for source categories with

relatively small NOX emissions (e.g.,

iron and steel mills, nitric acid

manufacturing sources, space heaters,

lime kilns, recovery plants, and engine

test facilities). Further discussion

concerning why controls were not

assumed for these source categories may

be found in Section III of this preamble.

e. Conclusion. The above discussion

described the controls for various source

categories that EPA considers to be

highly cost-effective. The next step in

the process is to determine the amounts

of NOX emissions that would be

eliminated by applying these highly

cost-effective controls to the respective

source categories. The EPA considers

those emissions to be the amounts that

contribute significantly to

nonattainment in, or interfere with

maintenance by, downwind States. By

assuming that reductions of this

magnitude should occur, EPA

determined the resulting State-specific

‘‘budget.’’ Section III, Determination of

Budgets describes the process EPA used

to determine each State’s budget and

discusses comments received on the

NPR.

E. Other Considerations

As described above, EPA determined

the amount of emissions that

significantly contribute to downwind

nonattainment from sources in a

particular upwind State primarily by (i)

evaluating, with respect to each upwind

State, several air quality related factors,

including determining that all emissions

from the State have a sufficiently great

impact downwind (in the context of the

collective contribution nature of the

ozone problem); and (ii) determining the

amount of that State’s emissions that

can be eliminated through the

application of cost-effective controls.

Before reaching a conclusion, EPA

evaluated several secondary, and more

general, considerations. These include:

• The consistency of the regional

reductions with the attainment needs of

the downwind areas with

nonattainment problems

• The overall fairness of the control

regimes required of the downwind and

upwind areas, including the extent of

the controls required or implemented by

the downwind and upwind areas

• General cost considerations,

including the relative cost-effectiveness

of additional downwind controls

compared to upwind controls This

section discusses these additional

considerations.

1. Consistency of Regional Reductions

With Attainment Needs of Downwind

Areas

a. General Discussion. Currently, air

quality levels in the eastern part of the

United States are above the 1-hour

NAAQS in various, primarily urban,

areas. Air quality levels are also above

the 8-hour NAAQS in those same areas,

as well as many others.

The OTAG, and subsequently EPA,

have conducted region-wide air quality

modeling, using the UAM-V model,

which shows that in approximately 20

primarily urban areas, the 1-hour

nonattainment problem will persist by

the year 2007, even after all of the

controls specifically required under the

CAA as well as Federal measures are

implemented.56 This nonattainment

problem that remains after

implementation of those mandated

controls may be termed ‘‘residual

nonattainment.’’ For the 8-hour NAAQS

modeling shows that under the same

circumstances, at least one urban area

that is linked to each upwind State will

continue to experience residual

nonattainment, and significantly more

areas will be in nonattainment as well.

Further, as discussed above, OTAG’s

subregional modeling as well as EPA’s

CAMx modeling and State-by-State

zero-out UAM–V modeling, indicate

that upwind States contribute

significantly to those downwind

nonattainment problems under both

standards. In general, under the 1-hour

standard, emissions from each upwind

State affect at least several, primarily

urban, nonattainment areas downwind.

For example, each of the midwest/

southern States of Ohio, Kentucky,

Tennessee, West Virginia, Virginia, and

North Carolina affects between five and

eight downwind nonattainment areas.

Under the 8-hour standard, emissions

from each upwind State affect

nonattainment problems that comprise

an even larger geographic area. For

example, Ohio, Kentucky, Tennessee,

West Virginia, Virginia, and North

Carolina each affect between eight to

thirteen downwind States with

nonattainment problems.

As described in section IV below, EPA

has conducted additional regionwide

modeling which shows that upwind

reductions comparable to those required

under today’s rule have an appreciable

impact on downwind nonattainment

problems under both NAAQS. The

downwind impact from each individual

upwind State’s reductions may be

relatively small, but the impact from all

upwind reductions, collectively, is

appreciable. This regionwide

modeling— which employs the UAM–V

model relied upon by OTAG and also

used by EPA for today’s action—

indicates that even after implementation

of the regional reductions, which help

downwind areas make progress toward

attainment, certain downwind areas

under the 1-hour NAAQS, and

numerous downwind areas under the 8-

hour NAAQS, will experience residual

nonattainment. In addition, under the 8-

hour NAAQS, many other areas with

nonattainment problems are expected to

reach attainment based solely on the

regional reductions.

Furthermore, as mentioned earlier,

the above-described modeling indicates

no upwind States whose required

regional reductions, in combination

with the other regional reductions and

CAA required controls, provide more

ozone reduction than is necessary for

every downwind nonattainment

problem affected by that upwind State

to attain under each NAAQS. That is,

there is no instance of ‘‘overkill,’’ so that

none of the upwind reductions required

under today’s action is more than

necessary to ameliorate downwind

nonattainment.

b. 8-Hour Nonattainment Problems.

As indicated above, the upwind

reductions are useful in ameliorating

downwind nonattainment under both

NAAQS, but they are particularly useful

in areas with nonattainment problems

under the 8-hour NAAQS because more

areas have such problems under that

standard. Emissions reductions from

each upwind State affect a broader

swath of downwind 8-hour

nonattainment problems, including

problems adjacent to, and further away

from, the upwind State. For example,

emissions from Ohio affect

nonattainment problems in each State

adjacent to Ohio, as well as numerous

States further away. As noted above, in

some cases, the upwind reductions

eliminate the downwind nonattainment

problem; in other cases, those

reductions ameliorate the downwind

problem but residual nonattainment

remains.

Moreover, under the 8-hour NAAQS,

upwind contributions tend to be a

particularly large percentage of the

downwind nonattainment problem. For

example, along the Northeast corridor,

cumulatively upwind States including

adjacent States, contribute 83 percent of
57404 Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations

57As noted in Section II.A., EPA proposed two

analytical approaches, the second of which is the

same as EPA is today promulgating. The

commenters’s criticisms seem to apply equally to

both approaches.

Washington, DC’s nonattainment

problem; 68 percent of Maryland’s

nonattainment problem; 65 percent of

Pennsylvania’s nonattainment problem;

and 85–88 percent of each of New

Jersey’s, New York’s, Connecticut’s, and

Massachusett’s nonattainment

problems. These high levels of upwind

contributions to widespread

nonattainment problems—both near to,

and far from, the upwind State—

indicate that the regional reductions

from the upwind areas may be expected

to be useful in ameliorating downwind

nonattainment under the 8-hour

NAAQS.

c. Commenters’ Concerns.

Commenters argued that in the NPR that

EPA failed to demonstrate that the

proposed reductions in upwind

emissions were necessary for downwind

areas to demonstrate attainment.

Commenters pointed out the lack of

local attainment demonstrations under

the 1-hour NAAQS.57

The EPA does not believe a local

attainment demonstration is required

before EPA can call on upwind States to

reduce emissions pursuant to section

110(a)(2)(D). The EPA believes that

available modeling analyses

demonstrate that upwind reductions are

necessary to help downwind areas come

into attainment. The OTAG and EPA

subregional modeling, UAM–V State-byState zero-out modeling, and the CAMx

modeling, described above, link each

upwind State’s emissions and

downwind attainment needs, in a

manner that is sufficient to support

today’s action. To reiterate, under the 1-

hour NAAQS, the emissions reductions

from each upwind State, combined with

other emissions reductions, are needed

to reduce downwind nonattainment

problems. That need is underlined by

the fact that the modeling relied on for

today’s action indicates residual

nonattainment after implementation of

all required controls and Federal

measures. Even after implementation of

the regional reductions, there is residual

nonattainment for at least one

downwind area linked to each upwind

State. The same is true for the 8-hour

NAAQS, as noted above.

The EPA recognizes that in the future,

additional information may become

available that would shed further light

on the amount of emissions reductions

needed for downwind areas to attain the

NAAQS. Local-scale modeling may

indicate more precisely the ambient

impact of regional and local reductions

on downwind nonattainment areas and

the amount of any residual

nonattainment. Nevertheless, it should

be emphasized that the models relied on

for today’s action are state-of-the-art,

and that their various inputs—

particularly the inventories—have

recently undergone close scrutiny and

careful refinement through public

comment and expert analysis.

Accordingly, EPA believes that the

overall model results indicating the

general impact of upwind emissions and

reductions in emissions should be

viewed as valid. Accordingly, EPA

believes that it has an adequate base of

information to require the regional

reductions under the 1-hour and 8-hour

NAAQS at this time.

2. Equity Considerations

The EPA believes further justification

for today’s action is provided by overall

considerations of fairness related to the

control regimes required of the

downwind and upwind areas, including

the extent of the controls required or

implemented by those areas.

The OTAG and EPA modeling

analyses clearly indicate that upwind

emissions contribute more than trivial

amounts to downwind nonattainment

problems. As a result, upwind emitters

are exacerbating the health and welfare

risks faced by those who live and work

in downwind areas afflicted with

unhealthful levels of ozone. The EPA

believes that the principle of simple

fairness applies here: upwind States

should reduce their emissions that visit

those health and welfare problems upon

their downwind neighbors. Otherwise,

their downwind neighbors would be

obliged to pay additional costs to reduce

local emissions beyond what would

otherwise be necessary to protect their

health from upwind emissions. In EPA’s

judgment, it is fair to require the

upwind sources to reduce at least the

portion of their emissions for which

highly cost-effective controls are

available. Indeed, fairness

considerations would point towards

requiring upwind reductions even if

there were some degree of cost

inefficiency.

Further, it should be recognized that

the major urban nonattainment areas

have been required to incur control

costs for ozone precursors since shortly

after the 1970 CAA Amendments. In

general, over the past quarter of a

century, these areas have implemented

SIP controls that, in combination with

Federal measures, place ozone-related

controls on virtually all portions of their

inventory of ozone precursors,

including VOCs as well as NOx. The Air

Quality Modeling TSD includes

descriptions of the control measures in

place for several major urban

nonattainment areas. Although not

every major urban nonattainment area

has complied with every CAA

requirement for ozone precursors, the

major urban nonattainment areas have

complied with almost all of these

requirements, and the CAA provides

remedies to assure complete

implementation of the required

provisions. These measures have

already lead to substantial reductions in

ozone levels. By comparison, upwind

States have not implemented reductions

intended to reduce their impact on

downwind nonattainment areas.

3. General Cost Considerations

The EPA also generally considered

the cost-effectiveness of additional local

reductions in the 1-hour ozone

nonattainment areas. The EPA

conducted this analysis as part of its

Regulatory Impact Analysis, completed

under Executive Order 12866, for the

rulemaking in which EPA revised the

ozone NAAQS, 62 FR 38866 (July 18,

1997). The EPA surveyed the additional

VOC and NOx controls available in areas

throughout the country that are

expected to be nonattainment under

either NAAQS. The EPA ascertained

that nationally, on average, these

additional measures would cost

approximately $4,300 per ton removed

during the ozone season. See ‘‘Control

Measures Analysis of Ozone and PM

Alternatives: Methodology and Results,’’

July 17, 1997, table VII–2, p. 56.

Although this figure is a national

average, it provides a basis to conclude

that local reductions may be expected to

be more expensive than the

approximately $1,500 in cost per ozoneseason ton removed for the regional NOx

reductions required in today’s

rulemaking.

Commenters criticized EPA’s proposal

to measure cost-effectiveness in terms of

cost per ton of emissions removed

because it did not take into account the

ambient impact downwind of the

emissions reductions. Commenters

cautioned that under certain

circumstances, a high level of emissions

reductions upwind may result in high

costs (even though cost-effective on a

per-ton basis), but relatively little

ambient benefit downwind.

Commenters emphasized that emissions

reductions tend to have the greatest

ambient benefit when they are within,

or adjacent to, the area with the

nonattainment problem. Commenters

also said that emissions reductions

further upwind have less ambient

benefit. Accordingly, commenters stated

that EPA’s cost-effectiveness
Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations 57405

58Although the reductions required of any one

individual upwind State under today’s rule may

not, by themselves, result in large ambient impacts

downwind, those reductions, when combined with

reductions from other upwind States, do result in

appreciable reductions downwind.

justification did not support its

proposed reduction requirements.

The EPA acknowledges the concerns

expressed by the commenters that

focusing solely on the cost effectiveness,

defined in terms of cost per ton

removed, of the emissions reductions

would exclude consideration of the total

costs incurred by the upwind sources,

and would exclude consideration of the

downwind ambient benefits that those

costs achieve, compared to the costs of

achieving the same ambient impact

through either local reductions or more

extensive reductions in adjacent

upwind areas. The EPA further

acknowledges air quality modeling

makes clear that reductions in emissions

closer to the air quality problem have a

greater ambient impact.

However, EPA has not been presented

with, nor been able to develop, an

accurate comparison of the downwind

costs of emissions reductions that

would achieve the same ambient impact

as the regional reductions required by

today’s action. The EPA does not have

comprehensive information concerning

available local measures or their costs or

ambient impacts.

However, as a qualitative matter, EPA

believes that available evidence

indicates that the upwind costs are

reasonable not only in light of costeffectiveness per ton removed, but also

in light of the downwind ambient

impact of the emissions reductions.

Under the 1-hour NAAQS, emissions

from each upwind State generally affect

several downwind nonattainment urban

areas. Thus, matching the total ambient

impact of the emissions reductions from

the upwind State would require

emissions reductions in several

downwind areas.58

Although presently available

information does not permit a useful

quantitative comparison of total upwind

and downwind costs in terms of their

ambient impact, EPA believes that

upwind reductions replace local

reductions that, on a cost-per-ton

removed basis, may be expected to be

more expensive. Moreover, it should be

recognized that for all of the

nonattainment areas under the 1-hour

NAAQS, the residents have already

incurred substantial control costs to

eliminate part of the local contribution

to the air quality problem. Under these

circumstances, EPA considers it

equitable to require the upwind emitters

to offset their contribution to the

problem through at least the reductions

that are the most highly cost-effective—

in terms of cost-per-ton removed—

rather than require the residents of the

downwind area to offset those upwind

contributions through even more local

control measures.

Furthermore, under the 8-hour

NAAQS, the available information—

again, on a qualitative basis—indicates

that the upwind emissions reductions

replace a significantly greater set of

local measures. As indicated above,

emissions from each upwind State affect

a wide swath of downwind areas with

nonattainment problems. As a result,

the emissions reductions from the

upwind State replace local reductions in

numerous downwind areas. Moreover,

some of these downwind areas are

adjacent to the upwind State, while

others are further away. Thus, under the

8-hour NAAQS, EPA believes that the

qualitative case is even more vivid that

the upwind emissions reductions

replace substantial and costly local

measures.

Finally, with respect to the

meteorological phenomenon that

upwind reductions have less ambient

impact the further away they are from

the downwind nonattainment problem:

EPA modeled the ambient impact of

regional variations in the levels of

upwind emissions reductions. This

modeling, and its results, are discussed

in the Air Quality TSD. In brief, the

modeling results indicate that it is

neither more cost-effective nor more

beneficial to air quality to pursue

subregional variations in upwind

emissions controls.

4. Conclusion

For the reasons discussed above, EPA

believes that adequate information is

available to determine, on a qualitative

basis, that the upwind reductions

required by today’s action are

reasonable in light of the attainment

needs downwind, and that the costs of

those reductions are reasonable in light

of the costs the downwind areas would

otherwise face. For these and other

reasons noted elsewhere, EPA believes

that requiring the regional reductions in

today’s notice is a reasonable step to

take at this time.

Of course, as more comprehensive

information becomes available

(including additional modeling,

additional information concerning local

control options and costs, as well as

more refined regional air quality

information), EPA will continue to

examine the issue of regional transport.

In addition, as described in Section III.,

EPA expects to review the issue of

regional transport by the year 2007 and

may require additional steps by either

the upwind States or the downwind

States, or both, to address the issue

further. Even so, as noted above, the

information that is available provides no

evidence that the regional reductions

required today may prove not to be

needed.

III. Determination of Budgets

The EPA used the highly costeffective measures identified in Section

II.D. above to calculate the amounts of

emissions in each covered State that

will contribute significantly to

nonattainment or interfere with

maintenance in one or more downwind

States (the ‘‘significant amounts’’). This

Section further describes issues related

to cost-effective controls and the role of

these controls in the calculation of

budgets.

First, as described earlier in this

notice, EPA projected the total amount

of NOX emissions that sources in each

covered State would emit, in light of

expected growth, in 2007 taking into

account measures required under the

CAA (the ‘‘2007 base year emissions

inventory’’). The EPA then projected the

total amount of NOX emissions that each

of those States would emit in 2007 if

each such State applied these highly

cost-effective measures (2007 controlled

inventory). The difference between the

2007 base inventory and the 2007

controlled inventory for each covered

State is the ‘‘significant amount’’ that

the State’s SIP must prohibit to satisfy

section 110(a)(2)(D)(i)(I). Each covered

State’s 2007 controlled inventory—

referred to in this Section as the State’s

‘‘emissions budget’’—expresses the total

amount of NOX emissions remaining

after the State’s SIP prohibits the

‘‘significant amount’’ of NOX emissions

in that State. Each covered State must

demonstrate that its SIP includes

sufficient measures (of the State’s

choice) to eliminate those emissions,

and thereby meet its budget, in the time

frames discussed later in this notice.

A. General Comments on the Base

Emission Inventory

Background: In the NPR, EPA

solicited comment on technical

information used in revising the 1996

base year emissions inventories and the

growth and control assumptions used to

develop the 2007 projection year base

inventories. The EPA received over 200

comment letters (from industry,

associations, States, environmental

organizations, and U.S. Congressional

representatives) on the condition of

1996 base year and projected 2007

emission inventories. The EPA accepted
57406 Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations

proposed modifications to the extent

EPA was able to validate them.

As discussed in the NPR (62 FR

60318), EPA established a 120-day

comment period (ending March 9, 1998)

to address issues related to the proposed

rule. In order to develop revised

inventories used to recalculate the

budgets for final rulemaking in a timely

manner, EPA felt that comments

received after the March 9, 1998

deadline would be addressed only if

time and resources were available and

after directing attention to comments

received prior to the end of the

comment period. The EPA is legally

obligated under the Administrative

Procedure Act to respond only to

comments timely submitted during the

public comment period. Response to

comments timely submitted before the

end of the comment period fulfills

EPA’s obligation to 5 U.S.C. 553(c).

Although the Agency was not able to

address all comments submitted after

March 9, 1998, as discussed in Section

III.F.5. of this notice, EPA is allowing

commenters an additional opportunity

to request revisions to the sourcespecific data used to establish each

State’s budget. During this time, EPA

will be addressing those comments

submitted during the NPR and SNPR

comment periods which were not

addressed for reasons indicated above,

as well as evaluate comments that are

submitted per Section III.F.5. of the

NFR.

1. Quality

Comment: Commenters suggested that

the OTAG inventory may not be of

sufficient quality for use in the

modeling and budget determinations for

the non-EGU point, area, nonroad

mobile, and highway vehicle source

sectors. The commenters stated that

OTAG originally intended the

inventories to be used in analyzing

ozone transport mechanisms and the

effect of possible control measures, not

for establishing emission budgets as

EPA has proposed. Additionally, as one

commenter mentioned, many States had

prepared inventories only for their

moderate and above nonattainment

areas, so that the remainder of the

State’s counties were supplemented

with USEPA data. In contrast to these

criticisms, other commenters supported

the quality of the inventories and the

procedures used in their development.

Response: Under the initial OTAG

inventory collection process, the 37

States in the domain provided emission

estimates for each entire State. The

majority of the supplied data were 1990

State ozone SIP emission inventories,

but some States supplied data from later

years that reflected significant

improvement over the 1990 data.

Additionally, OTAG collected point

source data from the States to update

and revise existing emissions

inventories used by OTAG. The result of

these efforts was an improved emissions

inventory which OTAG utilized for

modeling as well as strategy analyses.

The EPA used the final OTAG version

of the inventory for the emission

estimates in the NPR, and then

improved the inventory with data

supplied by the States and industry

through the public comment period. As

a result, the revised emissions inventory

is the most accurate available for

modeling, strategy analyses, and budget

calculation purposes. The inventory has

been through numerous versions, each

version reviewed and extensively

commented on by States, industry, and

the public. These inventory data are

more accurate than any other data used

in the past as the basis for the various

State-specific SIP revisions (such as

rate-of progress SIP revisions or

attainment demonstrations). The EPA

considers it sufficiently accurate for

purposes of determining the budgets.

The EPA recognizes that emission

inventories change as more accurate

data or methods are developed for

estimating emissions. For inventory

changes that may be necessary after

final promulgation of the budgets, EPA

has a process for determining what

changes need to be made as well as how

the changes would be made to the

inventories. This is discussed in further

detail in Section III.F.5. of this notice.

Comment: Several commenters were

concerned that the initial State NOX

emissions inventories submitted by the

States were never quality-assured or

commented upon by the States, the

regulated community, or the public.

Some commenters suggested the

reevaluation of emissions estimates with

State, local, and industry support.

Response: Under the guidance of

OTAG, the initial emission inventories

submitted by the States were qualityassured by technical experts, including

State and local emission inventory

contacts, industry, EPA staff and

contractors, and the OTAG Emission

Inventory Technical Committee. As EPA

amended and modified the inventory for

use in the modeling for the NPR, SNPR,

and the budget analyses, additional

quality assurance was completed. The

most accurate inventory development

tools available at the time were used to

validate these data and to quality assure

emission calculations in these data

bases. Existing data sets, including the

NET data, the OTC NOX Baseline

emission inventory, EPA’S AIRS/AFS

major point source reporting system,

and EPA’s Emission Tracking System

(ETS), which contains data submitted

and certified as correct by the States,

were used for comparison purposes.

Where discrepancies were found, either

before, during, or after the public

comment period, States and industry

were contacted to clarify and support

revised emission estimates.

2. Availability

Comment: Commenters asserted that

the emissions inventory used for the SIP

modeling and budget calculations were

not made available for public review

along with the proposed rule. One

commenter stated that the emissions

inventory that forms the basis for the

NPR (the SIP Call inventory) did not

become available until the first week in

February 1998.

Response: On October 10, 1997, EPA

posted emissions data on the TTN for

use and review during the public

comment period (See NPR, 60318).

These data, in conjunction with the

OTAG inventories, were the basis of the

initial proposed budgets and modeling

analyses in the NPR. Thus, these data

were available to the public before the

beginning of the 120-day comment

period on the NPR, which allowed

ample time to develop budget,

modeling, and cost analyses for

submission during the comment period.

By notice dated January 28, 1998 (63 FR

4206), EPA issued a caution that

comments on the inventory must be

submitted by the March 9, 1998 closeof-public-comment date, so that EPA

could finalize the inventories and use

them for further analyses.

On February 3, 1998, in response to

initial public comments and internal

review of the initially released data,

draft amendments to the emissions

inventory were posted on the EPA’s

TTN site. These changes included the

addition of EGU sources less than or

equal to 25 MWe which were excluded

from the initial budget calculation,

correction of EGU growth factors, and

the reclassification to the non-EGU file

of some sources previously erroneously

identified by OTAG as EGU sources.

Erroneously omitted non-EGU point

source records were also added to the

emissions inventory. Area, highway,

and nonroad mobile source information

was not modified in this iteration. By

posting this data on February 3, 1998,

EPA allowed 5 more weeks for public

comment on the revised data, until the

conclusion of the comment period for

inventory data on March 9, 1998.

Because the revisions were fairly minor,

EPA believes this amount of time was

adequate. The EPA did receive
Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations 57407

comments by March 9, 1998 on the

revised data it had posted on February

3, 1998.

B. Electricity Generating Units (EGUs)

Background: To determine the budget

for each State’s electricity generating

sector, EPA developed an inventory of

baseline heat input (mmBtu) and NOX

emissions (tons/season) data for each

unit. In the NPR, EPA proposed to use

the higher, by State, of 1995 or 1996

heat input data to calculate baseline

heat input rates (62 FR 60352). The EPA

maintained this approach for the SNPR,

but added 577 smaller units to the State

budget inventories, which had

erroneously been omitted for the NPR.

These units included electricity

generating sources of 25 megawatts of

electrical output (MWe) or smaller and

additional units not affected under the

Acid Rain Program.

1. Base Inventory

Comment: Commenters suggested that

using the higher of 1995 or 1996

utilization rates for setting the baseline

for the EGU portion of the budget may

not be appropriate in all instances. In

general, commenters argued for various

degrees of flexibility in choosing the

baseline year(s) to be used for

calculation of budgets.

Response: As discussed below, EPA

has made corrections to the baseline

heat input data for a small number of

EGUs based on careful review of the

data supplied with source-specific

comments. Using 1997 CEMS data is not

a practical option because EPA has not

had time to extract from the Acid Rain

Emissions Tracking System (ETS) the 5-

month ozone season heat input values,

quality assure them, or publish them.

(Although EPA’s Acid Rain Program

intends to publish its 1997 Emissions

Scorecard later in 1998, this publication

will contain only annual, not ozone

season, data.) Accordingly, EPA has

finalized the EGU portion of the budget

for each State using the higher of the

1995 or 1996 ozone season heat input

values.

Comment: Commenters asserted

revisions were needed to the published

heat input data for some EGUs and

proposed related additional sourcespecific changes. Commenters on this

issue stated that inaccurate calculations

of heat input data resulted in significant

errors in the Statewide budgets. Several

suggested the need for revision before

calculation of final budgets. Many of

these commenters provided specific

data that they urged EPA to use in the

final budget setting process.

Response: The EPA has analyzed the

data submitted by these commenters

and, where warranted, has made the

requested adjustments. Approximately

200 corrections were made to the

baseline heat input data for EGU sector

inventories.

Comment: Commenters also noted the

need to further correct, for some States,

the listing of units in the electricity

generating sector inventory.

Commenters listed specific EGUs that

EPA should either include or remove

from the inventory, or for which EPA

should correct applicable baseline data

(e.g., capacity, operating parameters).

Several commenters argued that

substantial revision of the inventory was

necessary before setting budgets under

the final rulemaking.

Response: The EPA has analyzed the

data submitted by these commenters,

including following up with

commenters when needed to assure

proper interpretation of the data. Where

warranted, EPA has corrected the State

inventories of units and applicable

baseline data.

While the vast majority of corrections

consisted of adding small units (e.g.,

municipal generators and peaking diesel

units), combustion turbines, and

independent power producers not

affected under the Acid Rain Program,

some involved deleting units that are no

longer operational or have been

misclassified and, in actuality, are

industrial non-electricity generating

boilers. The net result is that EPA has

added approximately 800 units to the

State EGU inventories. The EPA

believes that these inventories are

sufficiently accurate to develop a

budget.

Comment: Commenters suggested

types and sizes of sources to include or

exclude from the electricity generating

sector inventory. As to the sizes of

sources to include in the inventory,

commenters on the NPR were roughly

split on the inclusion of units less than

or equal to 25 MWe. Several noted that

emissions from sources below this level

were negligible and should not be

included. One commenter noted,

however, that these sources should be

included in the final budget because

they tend to operate on peak demand

days which frequently correspond to

high ozone days. Several suggested that

15 MWe be the cutoff for the utility

component of the budget.

On a separate concern, a few

commenters disagreed with the

inclusion of non-utility power

generators in the utility list of sources

and proposed that they be included

with industrial non-electricity

generating unit sources.

Response: Many of these comments

appear to confuse discussions of other

related issues (e.g., core sources for NOX

cap and trade rule, appropriate sources

for cost-effective control) with the types

and sizes of EGUs to be included in the

baseline inventory for setting the

budget. All emissions should be

included in the base inventory and,

thus, in the budget. As noted

previously, using information supplied

by commenters, EPA has agreed to add

many small units to the base inventories

of several States. Concurrently, EPA has

also decided not to classify EGUs less

than or equal to 25MWe as core sources

for the trading program, as discussed in

Section VII of this notice, or to assume

an emissions decrease for these small

units (‘‘cutoff level’’) as part of

Statewide budgets for EGUs.

The EPA maintains its decision to

include industrial units that generate

electricity in the definition of EGUs is

entirely consistent with the changing,

more competitive, character of today’s

electric power generation industry in

the US. Also, these units are amenable

to the same NOX control technologies, at

generally the same cost-effectiveness, as

utility units.

2. Growth

Background: In the NPR and SNPR,

EPA used forecasts of future electricity

generation to apply State-specific

growth factors in calculating the

emissions budgets for the electricity

generating sector. In the SNPR, EPA

revised the growth factors (the

‘‘corrected’’ projections) to account for

projected new combustion turbine and

combined cycle units inadvertently

excluded in the analysis developed in

support of the NPR. The EPA also

discussed in the SNPR that ‘‘revised’’

electricity generation projections could

lead to lower growth rates, and therefore

lower budgets, and placed supporting

information in the docket. However,

EPA proposed to use the ‘‘corrected’’

projections in calculating State budgets

to provide additional compliance

flexibility to sources and States (63 FR

25905).

a. Growth Rates.

Comment: The EPA received

approximately 36 comments in response

to the NPR and roughly 28 comments in

response to the SNPR regarding the

estimated growth rates that were used to

determine the NOX budget for each

State. These comments were submitted

by State agencies, associations, utilities,

and a public interest group.

Commenters expressed concern

regarding a number of specific issues,

including the following:

(i) the appropriateness of using

growth factors to determine the NOX

budget,
57408 Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations

59The Base Case is the condition of the industry

in the absence of the SIP call.

(ii) use of the IPM model to establish

the growth factors for each State, and

(iii) the use of the ‘‘corrected’’ instead

of the ‘‘revised’’ projections.

Some of these commenters opposed

growth factors generally, but many of

them supported the concept of—but not

the method proposed for—applying a

growth factor.

Response: The OTAG’s technical

analyses of NOX emissions suggested

that EPA needed to consider the electric

power industry’s future growth in

determining the amount of NOX

reduction that would be reasonable for

the power industry to make in the

future. The OTAG factored the growth

of the power industry’s emissions from

1990 to 2007 into the air quality

analysis that it performed. The results of

this analysis were the basis of its

recommendations to EPA to lower NOX

emissions from the power industry in

many Eastern States. Because the

Agency made its predictions about

attainment in 2007 based on projections

of emissions considering growth, rather

than on historical emissions, the Agency

also believes that the State budgets to be

used up to 2007 should account for

growth in electricity demand. Not

accounting for growth in demand for

electricity would require States to

reduce emissions below the level that

EPA predicted was necessary to reach

attainment. By accounting for growth

through 2007 and applying that growth

beginning in 2003, EPA essentially

allows sources to emit at a slightly

higher level than 0.15 lb/mmBtu in the

years 2003 through 2006.

In today’s action, the Agency has

determined to continue to incorporate

growth out to 2007 in developing State

budgets for summer NOX emissions. Not

accounting for growth would mean that

additional control measures—to offset

growth—would be required, and EPA

has not determined that those additional

control measures would be costeffective. In considering growth, EPA

has determined to continue to use either

1995 or 1996 State-wide heat input data,

for whichever year was higher for units

over 25 megawatts that burn fossil fuels

for baseline data. (More details on this

approach can be found above in Section

III.B.1. Base Inventory).

To estimate growth, EPA considered

several options. Ultimately, the Agency

has decided to use State-specific growth

factors derived from application of the

Integrated Planning Model (IPM) using

the 1998 Base Case 59 (also referred to as

the ‘‘revised’’ growth factors). This is

the same Base Case used for the

Regulatory Analysis in support of the

SNPR. The reasons for using these data

are discussed below under ‘‘Use of

IPM.’’

b. Use of IPM.

Comment: Many commenters

questioned whether use of the IPM

model was appropriate to derive

accurate State-specific growth factors.

Commenters expressed concern that

there was too much variation between

each State’s individual growth rate as

determined by the IPM model, and

suggested that use of region-wide IPM

growth factors may be more appropriate.

They also questioned the reliability and

accuracy of the IPM model, especially as

applied on an individual State basis. A

number of commenters stated that EPA’s

growth projections were lower than

growth rates projected in the context of

State utility planning efforts. Several

commenters suggested that EPA base its

growth rates on projections other than

OTAG, or EPA’s IPM forecasts; they

especially urged the Agency to consider

individual State-prepared forecasts.

This was to avoid problems that

commenters believe exist in EPA’s use

of the IPM model for forecasting

electricity generation in various areas of

the country. Specific concerns focused

on:

(i) the effect of IPM projections and

associated NOX budgets on future

growth within each State, and

(ii) how the IPM model accounts for:

—planned nuclear unit retirements,

—the impact of a deregulated utility

marketplace, and

—improvements in energy efficiency

and control technology.

Many commenters also generally

expressed concern that there is

insufficient information or

documentation on how EPA used the

IPM model to determine growth factors.

Many commenters asserted that EPA

should not incorporate the growth

factors into the budget calculation

process. These commenters argued that

adding growth to baseline activity and

subsequently applying controls reduces

the stringency of the standards, and

introduces an unacceptable level of

uncertainty. They suggested that the

budgets should be based on historic

utilization rates, and that States could

then determine how to allocate their

budgets to provide for growth. These

commenters recommended that, if a

growth factor must be used, then EPA

should apply a uniform growth rate

region-wide to determine the NOX

budget for each State.

Response: The EPA initially

considered using the OTAG growth

rates, but found that they were largely

based on past, State-specific generation

trends and did not factor in the more

competitive electric power market

where electricity will be increasingly

moving between regions in response to

the cost of producing electricity. The

Agency also found that there were

several other major limitations that were

described in the NPR. (62 FR 60352–

60353).

The Agency considered setting the

State NOX budgets based on past

generation levels in States, but this

approach also does not consider how

competition in the industry in the future

will alter electricity generation

practices. It ignores growth and shifts in

production altogether. A variant of this

approach, suggested by several

commenters, would be to use a uniform

growth factor for all States based on

some projection of future growth

through the 23 jurisdictions covered by

this rule. This approach appears evenhanded, but EPA views it as unfair and

inaccurate with respect to States in

which:

(i) utilities are particularly

economical to operate, and

(ii) the generation of power by these

firms is expected to grow at a rate

greater than average.

Another similar alternative suggested

in the public comments was that EPA

use a uniform growth factor for all

States in the same region, e.g., the North

American Electricity Reliability Council

(NERC) regions, or subregions. The

problem with this approach is, again,

that certain States within the same

region are expected to vary in their rate

of growth, given differences in their

electric utilities. The fact that some

States are in several NERC regions also

makes this approach less practical.

The Agency looked at several wellrecognized forecasts of regional

electricity generation growth, such as

those provided by NERC, the Annual

Energy Outlook of the Energy

Information Administration (EIA), and

Data Resources Incorporated’s (DRI)

World Energy Service U.S. Outlook.

None of these modeling systems

provides results at the State level.

Therefore, the Agency would have to

develop ways to apportion these

regional predictions to States. The EPA

knows of no way to apportion these

regional values to States that would

resolve the concerns expressed by

commenters. Furthermore, the Agency

uses the growth rates from IPM to

calculate the cost-effectiveness of NOX

emission reductions, as well as to

determine NOX budgets for States.

Therefore, using growth rates that are

not from IPM would lead the Agency to

using one set of State-specific
Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations 57409

generation estimates to develop NOX

budgets and a different set of Statespecific generation estimates for

determining cost-effectiveness. As a

result, EPA’s evaluations of future

activities of the power industry might

not be considered consistent. Finally,

although each of these sources provides

reasonable electricity generation

forecasts, each of the forecasts could be

criticized for the assumptions they make

in a manner similar to the way

commenters have criticized growth

factors from IPM.

Some commenters suggested that the

Agency use individual State forecasts

instead of IPM forecasts, including

projections used for State utility

planning efforts. The EPA rejected this

type of approach for two reasons. First,

nothing in the comments suggested to

EPA that the State forecasts are more

accurate or more reliable than the IPM

forecasts. Instead, the State forecasts

varied State by State in the way they

predicted future electricity generation.

Adoption of these forecasts could result

in inconsistencies in setting the State

budgets. Electricity generation forecasts

require making many technical

assumptions which, admittedly, lead to

some uncertainty in the results.

Accordingly, the Agency believes that

the fairest way to determine emissions

budgets is to handle these assumptions

in a consistent way for all of the States,

as long as a reasonable approach and

reasonable modeling assumptions are

used.

Therefore, EPA has decided to use the

IPM 1998 Base Case emissions forecast

for deciding State NOX budgets in

today’s action. The Agency finds it to be

the fairest and most reliable overall

approach to estimating growth factors. It

deals consistently with the technical

assumptions that occur in energy

forecasting and employs a reasonable set

of assumptions in the process of making

a forecast. As an added advantage, it has

undergone considerable review by the

electric power industry over the last two

years, and the industry was aware that

it might be applied as it is in today’s

rulemaking. Finally, EPA’s use of IPM

for forecasting State growth rates

provides for overall consistency in

forecasting future emissions and

estimating the cost-effectiveness of

reductions in this rulemaking.

The EPA believes that IPM provides a

reasonable forecast of State growth rates

because it carefully takes into account

the most important determinants of

electricity generation growth that are

facing the power industry today. These

major factors include: regional demands

for electricity, the impacts of wholesale

competition that lead to changes in

market share for various utilities,

changes in fossil fuel prices, expected

improvements in electricity generation

technology, costs of emission control

technology, expected changes in

generation unit operations and regional

dispatch practices to lower production

costs, nuclear unit retirements,

alteration in planning reserve margins to

meet peak demand, and limitations in

moving power between regions due to

transmission constraints.

An explanation of how EPA uses IPM

to address these issues and other

important factors is included in EPA’s

Analyzing Electric Power Generation

under the CAAA, March 1998 (Docket

no. V–C–3). Because EPA’s assumptions

have been reviewed by the public over

the last two years and the Agency has

worked with EIA and other groups to

improve them in response to comments

and new information, the Agency

believes that it has made reasonable

assumptions for a Base Case forecast of

electric power generation.

c. Use of ‘‘Corrected’’ Growth Rates.

Comment: Some comments on the

SNPR expressed concern that the new

‘‘corrected’’ growth factors are

artificially inflated and will compromise

efforts to improve air quality throughout

the region. Some of the commenters

suggested that States should have the

flexibility to determine how to manage

emissions from new sources in the

context of the original growth factors

and NOX budgets proposed in the NPR.

Some of these commenters also stated

that it was unclear why EPA chose to

use the ‘‘revised’’ projections in its cost

analysis but retained the ‘‘corrected’’

growth factors in its budget calculations.

Other commenters, however, were

supportive of the new growth factors

and the use of the ‘‘corrected’’

projections. Finally, several commenters

requested that EPA further explain how

the ‘‘corrected’’ growth factors were

derived and subsequently used to

generate the NOX budgets.

Response: In the NPR, EPA proposed

a set of growth factors based upon the

1996 IPM Base Case forecast. In the

SNPR, EPA corrected the growth factors

used in calculating State budgets to

account for new generation that had

inadvertently been left out of the

original calculations (the ‘‘corrected’’

growth factors). On the basis of

comments that EPA has received on its

assumptions for forecasting electricity

generation throughout the country

during the last year, the Agency revised

a set of key assumptions at the

beginning of 1998. These assumptions

lead to a better projection of electricity

generation nationally, by region, and by

State. Therefore, the Agency has

decided to use the 1998 IPM Base Case

forecast over the 1996 IPM Base Case

forecast as the basis for its ‘‘revised’’

State growth estimates.

The recent important changes that

were incorporated into EPA’s use of IPM

in 1998 include using the most recent

NERC estimate of regional electricity

demand; the latest available EIA and

NERC generation unit data; updated fuel

forecasts; updated assumptions on

nuclear, hydroelectric, and import

assumptions (with special attention to

differences in summer use); and an

increase in the level of detail in the

model to more accurately capture the

transmission constraints that exist for

moving power between various regions

of the country. The Agency also updated

its assumptions on the size and

operation of all electricity generation

units of utilities and independent power

producers (with special attention to

cogenerators) and updated its

assumptions on planning reserve

margins and the costs of building new

generation capacity. For this, the

Agency relied heavily on information

compiled from utilities by NERC and

the EIA. Each of these agencies has

regular contact with the power industry

and has its data reviewed by the power

industry. Again, details on these

improvements in IPM can be found in

EPA’s Analyzing Electric Power

Generation under the CAAA, March

1998 (Docket no. V–C–3).

In the SNPR, EPA used the ‘‘revised’’

growth factors in the IPM model in its

cost analysis but used the higher,

‘‘corrected’’ growth factors to calculate

State budgets. The EPA proposed the

higher growth factors because the

Agency believed that this results in less

cost and more flexibility for sources to

achieve their budget reductions

beginning in 2003. However, some

commenters pointed out that EPA had

provided sufficient flexibility by

accounting for growth to the year 2007

and applying that growth estimate

beginning in 2003. These commenters

remarked that it was not necessary to

add further flexibility by using the

higher, but less current and less

accurate, ‘‘corrected’’ growth rates. They

also stated that EPA should use the most

up-to-date information available. The

EPA agrees and is using the ‘‘revised’’

growth rates based upon the 1998 IPM

Base Case forecast to calculate the State

budgets used in today’s final rule.

3. Budget Calculation

a. Input vs. Output.

Background: In the SNPR, the

component of each State’s budget

assigned to electricity generation was

determined using the State’s total heat
57410 Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations

input, applicable emission rate (0.15 lb/

mmBtu), and projected growth in total

heat input to 2007. The Agency solicited

comment on an alternative approach to

calculating the State’s budget using each

State’s share of the 23 jurisdiction

electricity generation (electrical output).

The SNPR describes in detail the

output-based approach, and its possible

benefits as advanced by its proponents

(63 FR 25907). The Agency asked for

comments on the appropriateness,

legality, rationale, and methodology for

incorporating the output-based

approach when calculating the

electricity generation component of

each State’s budget.

Comments: The Agency received

comments both supporting and

opposing output-based State budgets.

Supporters of output-based budgets

asserted:

• An output-based budget would

promote competition among different

types of electricity providers on an

equal basis in a deregulated electric

utility industry.

• An output-based budget would

promote CO2, mercury, SO2 and offseason NOX reductions beyond what

would occur under a system that assigns

State budgets based upon input.

• An output-based budget may result

in more cost-effective NOX reductions.

• Issuing output-based budgets is

legally permissible.

The commenters opposed to outputbased State budgets objected to the

allocation of allowances to non-NOXemitting units, such as nuclear,

hydroelectric, solar, or geothermal

power plants. They claimed that this

would make compliance more difficult

and more costly for fossil-fuel burning

sources because fewer allowances

would be allocated to them.

Commenters opposed to output-based

budgets also claimed that:

• Output-based budgets would not

necessarily improve energy efficiency

compared to existing incentives, such as

fuel costs.

• The output-based State budgets may

not result in the same geographic

distribution of emissions as would

occur under the original budget

allocation.

• There could be significant

administrative problems with changing

the basis of the State budgets.

In addition, some commenters,

though in general supporting allocations

by output, specifically objected to

allocating allowances to nuclearpowered units because they believed

that this method would encourage

nuclear-powered electrical generation,

which, they further believed, would

have adverse ancillary impacts on the

environment.

The Agency received additional

comments on the method of allocating

State budgets to sources. Further

discussion of these comments can be

found in Section VI.C.2 of this

preamble.

Response: The EPA has an extensive

history of promoting the efficient use of

natural resources, particularly energy,

through both voluntary and regulatory

measures. Key emissions standards,

such as the standards for new vehicles

and the recently promulgated new

source performance standards to new

power plants, are written as outputbased fuel-neutral performance

standards that promote the efficient use

of energy. The EPA has begun to work

with States to find mechanisms to more

directly credit the use of energy

efficiency measures in SIP. The EPA

also has a number of programs that

encourage the use of energy efficient

technologies by providing energy users,

particularly in the residential,

commercial and industrial sectors, with

information on the economic and

environmental benefits of such

technologies.

Although the Agency has concluded,

for the reasons stated below, that heatinput-based budgets to States are more

appropriate at this time, the EPA

intends to work with stakeholders to

overcome existing obstacles and to

design an output allocation system that

could be used by States as part of their

trading program rules in their SIPs and

by EPA in future allocations to States.

The EPA considered how State NOX

budgets would be changed using the

output approaches suggested by the

commenters. The EPA revised its State

budget calculations using available

electrical generation data from the EIA

for utility and non-utility generators for

the higher electrical generation output

of either 1995 or 1996, by State. In Table

III–1 below, Column 2 presents the

proposed budgets based upon heat

input. Column 3 presents the revised

budgets based upon heat input and the

revised growth factors. Column 4 shows

output-based budgets, based upon all

electrical generation. Some commenters

suggested including fossil-fuel and

renewable energy source generation—

including hydroelectric, solar, wind,

and geothermal generation—but not

nuclear generation. These are included

in Column 5. One commenter suggested

using electrical generation from fossilfuel only, which is included in Column

6.

TABLE III–1.—STATE BUDGETS BY ENERGY SOURCE BASIS

(Higher of 1995 or 1996 EIA data]

Column 1 Column 2 Column 3 Column 4 Column 5 Column 6

State

Proposed

input-based

budgets fossil

fuel-burning

generators

Revised inputbased budgets

fossil fuelburning generators

Output-based

budgets all

generation

sources

Output-based

budgets—all

generation

sources except nuclear

Output-based

budgets fossil

fuel-burning

generators

Alabama ................................................................................ 30644 29026 34832 35068 32744

Connecticut ........................................................................... 5245 2583 7677 5156 4456

Delaware ............................................................................... 4994 3523 2392 3214 3417

District of Columbia .............................................................. 152 207 100 133 142

Georgia ................................................................................. 32433 30255 32223 31713 30819

Illinois .................................................................................... 36570 32045 44253 27888 29602

Indiana .................................................................................. 51818 49020 32212 43285 45831

Kentucky ............................................................................... 38775 34923 24847 33389 34166

Maryland ............................................................................... 12971 15033 13284 12969 13212

Massachusetts ...................................................................... 14651 14780 11017 13248 13496

Michigan ................................................................................ 29458 28165 32275 32037 32457

Missouri ................................................................................. 26450 23923 19790 22700 23498

New Jersey ........................................................................... 8191 10863 12764 11227 11470

New York .............................................................................. 31222 30273 39503 39440 32114
Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations 57411

TABLE III–1.—STATE BUDGETS BY ENERGY SOURCE BASIS—Continued

(Higher of 1995 or 1996 EIA data]

Column 1 Column 2 Column 3 Column 4 Column 5 Column 6

State

Proposed

input-based

budgets fossil

fuel-burning

generators

Revised inputbased budgets

fossil fuelburning generators

Output-based

budgets all

generation

sources

Output-based

budgets—all

generation

sources except nuclear

Output-based

budgets fossil

fuel-burning

generators

North Carolina ....................................................................... 32691 31394 32006 30156 29866

Ohio ...................................................................................... 51493 48468 39790 47143 50019

Pennsylvania ......................................................................... 45971 52006 53450 47014 48476

Rhode Island ......................................................................... 1609 1118 2242 3012 3202

South Carolina ...................................................................... 19842 16290 23252 14085 13831

Tennessee ............................................................................ 26225 25386 26410 26084 24770

Virginia .................................................................................. 20990 18258 19091 15700 15567

West Virginia ......................................................................... 24045 26439 22853 30708 32527

Wisconsin .............................................................................. 17345 18029 15745 16637 16324

Total ............................................................................... 563785 542007 542007 542007 542007

The Agency then calculated the

effective NOX emission rate for each

State in terms of lb/mmBtu, assuming

that the entire electricity generation

component of the budgets, as

determined by the input or output

methods, were allocated to the electric

generating units (EGUs). The Agency

wanted to evaluate whether the effective

NOX emission rate would be too low to

prove feasible absent participation by

the State in an interstate NOX emission

trading program. The EPA found that

under output-based State budgets from

all generation sources, three States

would need to impose an effective

emission limitation of 0.10 lb/mmBtu or

less on their fossil-fuel burning

electricity generators (see Column 3 in

Table III–2 below). One State would

need to impose an emission limitation

of 0.07 lb/mmBtu. Such a low effective

emission limitation may not be

technically achievable if a State chooses

not to join an interstate allowance

trading program, unless the State

requires some sources to shutdown. In

contrast, the Agency found that it was

feasible and cost-effective to make

reductions even without an interstate

NOX trading program under an inputbased State budget calculated using a

uniform NOX emission rate of 0.15 lb/

mmBtu.

TABLE III–2.—EFFECTIVE EMISSIONS RATES FOR EACH STATE BY OUTPUT BASIS

[Higher of 1995 or 1996 EIA data]

Column 1 Column 2 Column 3 Column 4 Column 5

State

Effective emission rate

under inputbased budgets

(Fossil fuel

burning generators) (lb/

mmBtu)

Effective emission rate

under outputbased budgets

(All generation)

Effective emission rate

under outputbased budgets

(all generation

except nuclear)

Effective emission rate

under outputbased budgets

(Fossil fuelburning generators)

Alabama ............................................................................................................ 0.15 0.18 0.18 0.17

Connecticut ....................................................................................................... 0.15 0.45 0.30 0.26

Delaware ........................................................................................................... 0.15 0.10 0.14 0.15

District of Columbia .......................................................................................... 0.15 0.07 0.10 0.10

Georgia ............................................................................................................. 0.15 0.16 0.16 0.15

Illinois ................................................................................................................ 0.15 0.21 0.13 0.14

Indiana .............................................................................................................. 0.15 0.10 0.13 0.14

Kentucky ........................................................................................................... 0.15 0.11 0.14 0.15

Maryland ........................................................................................................... 0.15 0.13 0.13 0.13

Massachusetts .................................................................................................. 0.15 0.11 0.13 0.14

Michigan ........................................................................................................... 0.15 0.17 0.17 0.17

Missouri ............................................................................................................ 0.15 0.12 0.14 0.15

New Jersey ....................................................................................................... 0.15 0.18 0.16 0.16

New York .......................................................................................................... 0.15 0.20 0.20 0.16

North Carolina .................................................................................................. 0.15 0.15 0.14 0.14

Ohio .................................................................................................................. 0.15 0.12 0.15 0.15

Pennsylvania .................................................................................................... 0.15 0.15 0.14 0.14

Rhode Island .................................................................................................... 0.15 0.30 0.40 0.43

South Carolina .................................................................................................. 0.15 0.21 0.13 0.13

Tennessee ........................................................................................................ 0.15 0.16 0.15 0.15

Virginia .............................................................................................................. 0.15 0.16 0.13 0.13

West Virginia .................................................................................................... 0.15 0.13 0.17 0.18

Wisconsin ......................................................................................................... 0.15 0.13 0.14 0.14
57412 Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations

Advocates of an output-based

approach contend that individual

sources would have the greatest

incentive to improve their efficiency,

relative to all other sources in the

program, if both State budgets and

individual source allocations were on

an output basis and were updated

periodically. For example, if a company

replaces a turbine with a more efficient

one, the unit supplying the turbine

would reduce the amount of fuel (heat

input) the unit combusts and would

reduce NOX emissions proportionately,

while the associated generator would

produce the same amount of electricity.

Thus, the company would receive the

same allowances if an output-based

allocation were updated after the

efficiency improvement. This same

company would receive fewer

allowances under a system that

reallocates based on heat input after the

efficiency improvement. The company

would keep the same allowance

allocation if it had a permanent

allocation, based upon either heat input

or output. With a permanent allocation,

the company would have more

allowances available than before its

efficiency improvements because of its

emission reductions, but fewer

allowances than if it had greater

electrical output recognized through an

updated allocation. Thus, of the four

approaches, an updated allocation based

upon output gives the greatest incentive

for improving efficiency in electricity

generation.

To provide an incentive within the

State budget determinations for

improving efficiency over time, EPA

would need to issue the State budgets

based upon output and periodically

update those State budgets. However,

many industry commenters wanted

long-term or permanent allowance

allocations to allow for compliance

planning. Updates to the State budgets

would require States to reallocate

allowances to their sources. In addition,

States (both upwind and downwind)

would find it easier to manage their

resources for improving air quality if

they receive a fixed budget for a period

of years. With a fixed budget, a State

would have the choice of whether to

periodically adjust allocations rather

than being required to periodically

reallocate allowances to its sources.

Finally, the Agency continues to have

concerns about data available to

establish the baseline for an outputbased State budget. The EIA withholds

some of the electricity generation

information it collects from non-utility

generators in order to protect source

confidentiality. Therefore, part of the

generation data required to establish

State budgets is not available to EPA.

Thus, EPA would have difficulty in

computing and defending State budgets.

In addition, some units are

cogenerators, which are electrical

generators that divert part of their

heated steam to provide heat (steam

output), rather than to generate

electricity. Information on steam output

from cogenerating units or from

industrial boilers is not currently

available to EPA. A cogeneration unit

that was included under the State

budget as an electricity generating unit

based upon heat input would only have

its electrical output included in an

output-based State budget, ignoring the

portion of heat input used to generate

steam output. Thus, output-based State

budgets based on currently available

data could inadvertently underallocate

budgets to States with many

cogenerators, which are some of the

most efficient units. This could actually

discourage improvements in efficiency

through cogeneration.

For the reasons stated above, the

Agency concludes that it is not

appropriate to develop output-based

State NOX emission budgets at this time.

However, the Agency does believe that

output-based allocations to sources

could provide significant benefits. As

stated earlier in this Section, the EPA

intends to work with stakeholders to

overcome existing obstacles and to

design an output allocation system

based on electricity and steam

generation that could be used by States

as part of their trading program rules in

their SIPs. In addition, EPA is proposing

FIPs for States that do not submit

adequate SIPs by the deadline required

by this final rulemaking. As part of its

proposal, the Agency is soliciting

comment on source allocations for each

State based upon both input and output.

While EPA believes that the output data

are not sufficiently complete or accurate

to use for final budgets or for final

source allocations at this time, the

Agency is taking comment on the

proposed allocations in order to receive

public comment and to develop more

accurate and more complete output data

that could be used in the final FIP

rulemaking.

The EPA does believe that, over the

long-term, it should continue to look at

the issues that surround the use of

output-based allocations. In addition, as

stated in Section III.B.5. of this

preamble, the Agency will review the

progress of States in meeting their

budgets in 2007. In that review, the

Agency will consider not only whether

the SIPs achieved the reductions that

had been projected to meet the budgets,

but also issues such as future budget

levels and allocation mechanisms

including shifting to an output-based

allocation method.

b. Alternative Emission Limits.

Comments: The EPA received

numerous comments on the proposed

uniform control level of 0.15 lbs/mmBtu

for the EGU sector assumptions across

the 23 jurisdictions. Many States

supported this proposed control

assumption. The EPA also received a

number of alternative proposals. These

contain emission-reduction assumptions

ranging from 0.12 lb/mmBtu to be

implemented on the schedule proposed

in the NPR to a phased approach that

starts with 0.35 lb/mmBtu to be

implemented by sector and provides for

further evaluation of the need for more

stringent levels. The latter commenters

based their recommendations on their

views that emissions from upwind

States do not have an ambient impact

that is as important as EPA believes, or

that implementation of the EGU control

levels proposed by EPA would not be

feasible by the date EPA proposed. In

addition, a number of utilities and other

commenters voiced concern that the

proposed control assumption of 0.15 lb/

mmBtu would be too stringent to

provide sufficient surplus allowances

for trading.

Response: At the time of the proposal,

EPA chose 0.15 lb/mmBtu as the

assumed uniform control level for EGUs

because it provided the greatest air

quality improvements feasible and was

cost-effective because its cost ($1,700

per ton NOX removed in the 5-month

ozone season) was, on average, within

the cost range of other controls that had

been recently promulgated or proposed.

The EPA also investigated the costs of

several alternative uniform control

options: 0.25, 0.20, and 0.12 (though

0.12 resulted in lower emission levels,

its average cost-effectiveness calculated

at the time of the proposal was $2,100/

ton, exceeding EPA’s target cost range of

$1,000 to $2,000/ton).

Subsequent to the NPR and SNPR,

EPA updated its EGU costing model

(IPM) and revised stationary source

emission inventories (based on public

comment). These revisions and

corrections lowered the average cost of

compliance for all the control levels

considered. Additionally, EPA

conducted extensive air quality

modeling of a number of alternative

control levels. The results of the air

quality analyses were examined using a

number of different metrics for both the

one-hour and eight-hour standards.

These air quality analyses are discussed

in more detail in Section IV of this

notice.
Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations 57413

The revised air quality analyses show

that there is no ‘‘bright line’’ to illustrate

at what control levels the air quality

benefits begin to diminish. The air

quality metrics suggest there are

corresponding incremental air quality

improvements at every incremental

control level. For example, tightening

the control level improves ozone levels

in many non-attainment areas and leads

to additional counties achieving

attainment under the one-and eighthour standards. All metrics analyzed

show that as the control level moves

from 0.25 to 0.20 to 0.15 to 0.12 lb/

mmBtu, air quality benefits increase.

The analyses also show that none of the

alternative control options results in

attainment of the ozone standard in all

nonattainment areas.

The EPA did not select levels higher

than 0.15 lb/mmBtu (such as 0.20 lb/

mmBtu or higher) because the 0.15 lb/

mmBtu level offers more air quality

benefits at a cost that is still highly costeffective. Moreover, EPA did not have

information to indicate that these higher

levels could be implemented

meaningfully sooner than controls at the

0.15 lbs/MmBtu level. The EPA

acknowledges that the 0.12 lbs/MmBtu

emission level is also within the average

cost-effectiveness range based on the

revised cost analysis. The incremental

cost-effectiveness of this option is

$4,200 per ton, an incremental cost per

ton which is 85 percent higher than that

for the 0.15 lb/mmBtu level. However,

for reasons explained Section II.D., the

EPA is not relying on this emission

level.

The revised IPM analyses project that

under the 0.12 control option, 54

percent of affected EGU capacity should

install selective catalytic reduction

(SCR) and 41 percent should install

selective non-catalytic reduction

(SNCR). The installation requirements

for SNCR are significantly less extensive

than for SCR. The analysis of the 0.15

lb/mmBtu control option projects 31

percent of affected EGU capacity should

install SCR and 54 percent should

install SNCR. Further, the technical

record provides many examples in the

United States and internationally of the

ability of coal-fired units to achieve

emission levels below 0.15 lb/mmBtu

with the installation of SCR. The record

contains fewer international examples,

and only one US example, of a coalfired unit’s ability to achieve emission

levels below 0.12 lb/mmBtu.

In terms of the proposed level of

control on which the trading program

budget is based, EPA believes that

trading at 0.15 lb/mmBtu is feasible

because the proposed limit can readily

be achieved by gas and oil-fired boilers.

In fact, more than 50 percent of gas and

oil-fired boilers already operate at NOX

levels below 0.15 lb/mmBtu and should

readily be able to generate emission

credits if affected States join a trading

program.

The EPA recognizes that for coal-fired

boilers to operate at or below a 0.15 lb/

mmBtu emission limit, SCR would

generally be necessary. Under a trading

scenario, however, if one coal-fired

boiler is able to emit below 0.15 lb/

mmBtu by installing SCR, it can provide

emission credits to another coal-fired

boiler and obviate the need for that

second boiler to install SCR.

A remaining issue is whether SCR can

achieve NOX levels below 0.15 lb/

mmBtu. The EPA believes that SCR

technology is capable both of reducing

NOX emissions by more than 90 percent

and reducing NOX rates below the

proposed 0.15 lb/mmBtu limit, provided

the appropriate regulatory incentive

(i.e., emission limit or economic

incentive) exists. As discussed in EPA’s

recent report, ‘‘Performance of Selective

Catalytic Reduction on Coal-Fired

Steam Generating Units,’’ emission rates

below 0.15 lb/mmBtu are currently

being achieved by a number of coalfired boilers using SCRs. Examples

include: (1) Three Swedish boilers

achieving rates between 0.04 and 0.10

lb/mmBtu; (2) six German boilers

achieving rates between 0.08 and 0.14

lb/mmBtu; (3) two Austrian boilers

achieving rates between 0.08 and 0.12

lb/mmBtu; and (4) four U.S. boilers

achieving rates between 0.07 and 0.14

lb/mmBtu. The EPA also recognizes that

these boilers, with the exception of the

Swedish boilers, have SCR systems

designed to achieve target emission

limits. As a result, they fail to provide

an accurate picture of the emission

levels which SCR is capable of

achieving below the target emission

threshold. For this reason, EPA cannot

confidently conclude that enough units

can feasibly achieve levels at 0.12 lbs/

MmBtu. In summary, EPA believes that

an emission rate of 0.15 lb/mmBtu

reflects the greatest emissions reduction

that EPA can confidently conclude is

feasible and that is highly cost-effective,

and provides ample allowances to

sustain a market under the NOX Budget

Trading Program.

c. Consideration of the Climate

Change Action Plan.

Background: The President’s Climate

Change Action Plan (CCAP) calls for

implementation of over 100 voluntary

programs aimed at reducing greenhouse

gas emissions. A large number of them

are aimed at reducing future electricity

demand throughout the country.

Already, some of these programs have

shown striking results in accomplishing

their energy efficiency objectives.

Comment: Two commenters noted

that it is inappropriate for EPA to

incorporate assumed reductions in

energy use based on the voluntary

measures of the CCAP, which are not

binding like a regulation.

Response: The EPA believes that it is

appropriate to incorporate the impact of

the voluntary measures in the CCAP on

future electricity demand. The EPA has

always believed that it is appropriate to

incorporate any reasonable assumptions

that the Agency can support that will

affect future electricity demand, or

electricity generation practices, into its

Base Case forecast. For example,

improvements in electricity generation

technology, fuel prices changes, and

other types of assumptions that are

important elements of EPA’s forecast of

electricity generation and resulting air

emissions are also not mandated by

regulation. The Agency has considered

the impact of the CCAP in using the IPM

model for analysis since 1996, and

documentation of the assumptions that

the Agency has been making have been

available for public review since April

1996. Until now, there have been no

challenges to this consideration in the

numerous reviews that there have been

of EPA’s documentation of how it uses

the IPM model. Also, no one has

challenged EPA’s specific approach to

factoring the CCAP into its electricity

generation forecast. (This can be

confirmed by examination of the

dockets for the Clean Air Power

Initiative and the Phase II Title IV NOX

Rule, records of EPA’s Science Advisory

Board, and the records of the Ozone

Transport Assessment Group meetings.)

The EPA updated its assumptions in

IPM for the CCAP at the beginning of

1998. The EPA updated its assumptions

in the same manner as it has done in the

past—by lowering the most recent NERC

demand forecast by the amount of

electricity demand between 2000 and

2010 that the best available analysis

suggests will occur due to the activities

in CCAP. The EPA used the in-depth

evaluation of the future implications of

the CCAP for reducing electricity

demand that was the basis for the

findings in the Administration’s Climate

Action Report, July 1997. The amount of

demand reduction that occurs appears

in Analyzing Electric Power Generation

under the Clean Air Act, March 1998.

The Climate Action Report analysis was

reviewed extensively within the Federal

government by EPA, the Department of

Energy and other Federal agencies, and

the report was reviewed publicly before

its publication. The EPA has not

received criticism that it has overstated
57414 Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations

the electricity demand reductions that

are the basis for the carbon reductions

under the CCAP.

Notably, the electricity demand

reductions were distributed evenly

throughout the United States, and

therefore have no influence on the share

of the total amount of NOX emissions

that each State receives. Furthermore,

the Agency examined the implications

on its cost-effectiveness determination

of not including the CCAP reductions in

its electricity demand forecast. The EPA

found that even if the Agency did not

assume the CCAP reductions, it was still

highly cost-effective to develop a

regional level NOX budget for the

electric power industry, based on the

level of control that EPA has assumed.

(These results appear in Chapter 6 of the

Regulatory Impact Analysis for the

Regional NOX SIP Call, September

1998.)

C. Non-EGU Point Sources

Background: The EPA developed the

NOX SIP call emissions inventory for

non-EGU point sources based on data

sets originating with the OTAG 1990

base year inventory. The OTAG

prepared these base year inventories

with 1990 State ozone SIP emission

inventories, and EPA supplemented

them with either State inventory data, if

available, or EPA’s National Emission

Trends (NET) data if State data were not

available.

For the SNPR, non-EGU point source

inventory data for 1990 were then

grown to 1995 using Bureau of

Economic Analysis (BEA) historical

growth estimates of industrial earnings

at the State 2-digit Standard Industrial

Classification (SIC) level. These

emissions were grown to 1995 for the

purposes of modeling and to maintain a

consistent base year inventory with the

EGU data. Because BEA data are

historical documentation of industry

earnings, EPA considered these to be

among the best available indicators of

growth between 1990 and 1995 (63 FR

25915). Once the common base year of

1995 was established for these source

categories, the BEA growth assumptions

utilized by OTAG were used to estimate

the 2007 base case inventory.

1. Base Inventory

Comment: The majority of comments

related to the non-EGU point source

inventory alleged that these inventories

were incomplete or inaccurate. The

comments generally addressed missing

sources, non-existent or retired sources,

incorrect source sizes, mis-classification

of processes, or emission allocation

inconsistencies. Many of these

commenters provided specific

adjustments to be made to the

inventories, including emissions

modifications, activity factors, source

sizes, and facility name changes. A

number of States supplied completely

new inventories to replace what was in

the proposed data sets. Other

commenters made broad, general

categorical comment on the quality of

the inventories with no supporting data.

Response: As was followed under the

OTAG inventory update procedures, all

State supplied comments were generally

incorporated ‘‘as is’’ with the

understanding that each State qualityassured its own data before submission.

Industry-supplied comments were

forwarded to respective State agencies

for review and where data were deemed

appropriate for inclusion, integrated

into the inventories. In some instances,

States responded that the data provided

by the State should override that

supplied by industry, or vice-versa.

Comments were, in some cases, not

incorporated when necessary to prevent

double counting of emissions in point

and area source inventories, where base

year emission modifications were

calculated from permitted emission

levels and not actual operating activity,

where additional supporting data could

not be provided by the commenter, or

where comments were general

characterizations of inventories or

inventory sectors. Note that even after

State review, if the EPA felt that the

data, procedures, methodologies, or

documentation provided with the

comment were not sufficient, valid, or

justifiable, comments, or portions

thereof, were excluded from the

revision.

Both 1990 and 1995 base year

emission and growth modifications

were submitted and where 1990 data

were provided, the methods described

earlier in this Section were utilized to

account for growth to 1995 and 2007

levels.

2. Growth

Comment: Several commenters

suggest that the growth factors used to

determine 2007 non-EGU point source

base year inventories are inaccurate or

inconsistent across regions and

categories of the inventory. They

explained that if growth factors are to be

used to estimate future base year

emissions, consistent national or regionwide values should be utilized for all

categories across all States within the

domain. This, they continue, would

promote equitable potential progress to

all areas and not penalize those that

have shown past poor growth rates.

Some commenters go on to state that

growth rates based on past growth

automatically disadvantage States

which have suffered from unusually low

growth rates. In addition to growth

rates, some commenters provided 2007

base year emission estimates either with

or without the growth and control

information needed to validate their

calculation.

Response: As noted above, EPA relied

on BEA State-specific historical growth

estimates of industrial earnings at the 2-

digit SIC level as among the best

available indicators of growth for nonEGU point sources. The BEA projection

factors assume the continuance of past

economic relationships. These factors

are published every five years and

adjusted to account for recent

production and growth trends. For this

reason, BEA data provide a useful set of

regional growth data that EPA

recommends for use in preparing

emission inventory projections. It is true

that BEA projection factors differ among

different areas and different source

categories because of historical

differences in industrial growth among

those different areas and source

categories. However, in general, these

projection factors offer the most reliable

indicators of future growth as are

available.

In cases where commenters

questioned the use of EPA’s growth

rates but provided no alternative of their

own, EPA had little choice but to

continue to use the BEA-derived growth

rates. Some commenters provided

alternative or supporting information for

modification of source category or State

growth estimates. In those cases where

a State or industry may have had more

accurate information than the BEA

forecast (e.g., planned expansion or

population rates), data were verified and

validated by the affected States and by

EPA, and revisions were made to the

factors used for that category.

3. Budget Calculation

Background: In the NPR and SNPR,

EPA proposed that EGUs with a

capacity less than or equal to 25 MWe

or 250 mmBtu/hour would be

considered small sources (‘‘cutoff

level’’) and, as such, EPA would not

assume an emissions decrease as part of

the Statewide budget for this group of

sources. At the same time, EPA

proposed 2 cutoff levels for industrial

(non-EGU) boilers and turbines: units

with a capacity greater than 250

mmBtu/hour were defined as large units

subject to a 70 percent emission

reduction assumption; units with a

capacity less than or equal to 250

mmBtu/hr but with emissions greater

than 1 ton/day were defined as medium

units subject to reasonably available
Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations 57415

control technology (RACT); and units

with a capacity less than or equal to 250

MmBtu/hr and with emissions less than

or equal to 1 ton per day were

considered small sources for which no

reduction would be assumed in the

budget. In the SNPR, EPA specifically

invited comment on the size cutoffs and

on treating large industrial combustion

sources (greater than 250 mmBtu or

approximately 1 ton per day) at control

levels equal to that for EGUs (63 FR

25909). As described below, this

approach has been modified somewhat

in response to comments and further

analysis.

a. Proposed Control Assumptions.

Comments: Some comments

supported EPA’s proposed approach of

assuming 70 percent and RACT controls

in its calculation of the budgets.

Numerous comments were received

stating that the 70 percent reduction is

inappropriate, may not be cost-effective

and may not be achievable, especially

for the following industries: cement

plants; municipal waste combustors;

certain pulp and paper operations,

including lime kilns and recovery

furnaces; glass manufacturing; steel

plants; and some industrial boilers.

Some comments suggested a control

level of 60 percent rather than 70

percent. On the other hand, one

commenter stated that SCR and SNCR

are applicable and have been installed

on hundreds of industrial sources.

Response: The EPA generally agrees

that 70 percent emissions reduction is

not appropriate for all large sources or

all large source categories, even though

SCR and SNCR are applicable and costeffective for many sources. Instead of

applying a one-size-fits-all percentage

reduction to all large non-EGU sources,

the specific emissions decreases

assigned to each of these source

categories for purposes of budget

calculation in the final SIP Call

rulemaking reflect the specific controls

available for each source category that

achieve the most emissions reductions

at costs less than an average of $2,000

per ton. As described elsewhere in this

notice, EPA’s analysis results in

calculating budget reductions ranging

from 30 percent to 90 percent for several

source categories and no controls to

several other source categories.

b. Small Source Exemption.

Comments: In general, commenters

were supportive of EPA including a

cutoff level as part of the budget

calculation; however, there were many

suggestions on what the cutoff should

be. The EPA received numerous

comments supporting the proposed

cutoff level of 25 MWe for EGUs, which

is approximately equivalent to 250

mmBtu/hr or one ton per day. In

addition, EPA received a few comments

supporting a 250 mmBtu/hr cutoff for

non-EGU point sources. Commenters

indicated that the levels were

appropriate and that it was important to

be consistent with cutoff levels in the

OTC’s NOX trading program. The Ozone

Transport Commission (OTC) comprises

the States of Maine, New Hampshire,

Vermont, Massachusetts, Connecticut,

Rhode Island, New York, New Jersey,

Pennsylvania, Maryland, Delaware, the

northern counties of Virginia, and the

District of Columbia. In September

1994, the OTC adopted a memorandum

of understanding (MOU) to achieve

regional emission reductions of NOX.

These reductions are in addition to

previous OTC state efforts to control

NOX emissions, which included the

installation of reasonably available

control technology. The OTC’s NOX

trading program requires utility and

nonutility boilers greater than 25 MWe

or 250 mmBtu to reduce emissions in

order to meet a NOX budget and allows

emissions trading consistent with that

budget. These NOX reductions will take

place in two phases, the first phase

beginning on May 1, 1999 and the

second phase on May 1, 2003.

Some comments suggested assuming

budget controls on units less than or

equal to 25 MWe at RACT levels

without a cutoff level. Others supported

EPA’s proposal of assuming no

additional controls on these sources.

Some comments suggested exempting

medium-sized non-EGU sources.

Many commenters supported the

general 1 ton per day exemption

contained in the NPR and SNPR.

However, a few comments suggested a

more stringent cutoff level of 50–100

tons per year, similar to definitions of

‘‘major source’’ in the CAA. One

commenter recommended a less

stringent level of 5 tons per day cutoff

level.

A few comments suggest using tons

per day as the primary criterion to

define large- and medium-sized nonEGU sources, rather than boiler

capacity. This approach would exempt,

for example, industrial boilers that

exceed the 250 mmBtu capacity, but

which emit less than one ton per day on

average. The EPA’s proposed approach

considers a source large if heat input

capacity data are available and exceed

the 250 mmBtu capacity criterion,

regardless of its average daily emissions.

In support of this approach, commenters

stated that industrial operations do not

usually operate at or near capacity,

while EGUs often do.

A few commenters indicated that the

OTAG recommendations for turbines

and internal combustion engines (in

terms of horsepower cutoff levels) be

used. OTAG had recommended cutoff

levels of 4,000 horsepower for stationary

internal combustion engines and 10,000

horsepower for gas turbines.

Response: For reasons described

below and in the NPR (62 FR 60354),

EPA believes that the cutoff levels of

250 mmBtu/hr and 1 ton per day for

large non-EGU point sources are

appropriate. The EPA selected 250

mmBtu/hr and 1 ton per day primarily

because this is approximately

equivalent to the 25 MWe cutoff used

for the EGU sector. Emission decreases

from sources smaller than the heat input

capacity cutoff level, and that emit less

than 1 ton of NOX per ozone season day,

are not assumed as part of the budget

calculation; these sources are included

in the budget at baseline levels.

The EPA believes that the 1 ton per

day exclusion contained in the NPR and

SNPR is appropriate and necessary. This

level allows today’s rulemaking to

focus, for the purpose of calculating the

budget, on the group of emission

sources that contribute the vast majority

of emissions, while at the same time

avoids assuming emissions reductions

from a very large number of smaller

sources (as described in the following

paragraph). In taking today’s first major

step towards reducing regional transport

of NOX, EPA does not believe that

emission reductions from these small

sources need to be assumed. This

approach provides more certainty and

fewer administrative obstacles while

still achieving the desired

environmental results. Although other

cutoff levels were suggested by

commenters, EPA believes that the

cutoff levels described above strike the

appropriate balance so that reasonable

controls may be applied by States to a

sufficient but manageable number of

sources to efficiently achieve the needed

emission reductions.

Most small sources emit less than 100

tons of NOX per year. Although their

total emissions are low, small sources

account for about 90 percent of the total

number of point sources. Thus, not

assuming controls on these sources at

the present time would greatly limit

administrative complexity and reporting

costs. This common-sense approach

results in reducing the non-EGU

population potentially affected by the

ozone transport rule from more than

13,000 sources estimated in the NPR

and SNPR to under 1,200.

Although a few comments suggested

using tons per day, not capacity (MWe

or mmBtu/hr), for setting cutoff levels,

EPA chose primarily to use capacity

indicators. This approach is consistent
57416 Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations

with the framework of the emissions

trading program. In addition, EPA is

concerned that units could have low

average emissions during the ozone

season but relatively high emissions on

some high ozone days. Accordingly,

EPA is relying on a capacity approach

first and a tons per day approach second

(where capacity data is not available or

appropriate) to define units for which

reductions are assumed in EPA’s budget

calculations.

As noted in the proposal notices,

horsepower data was generally absent

from the available emissions inventory

data. Thus, the OTAG recommendation

could not be used. Because quality

assured data are still lacking, EPA used

alternative approaches to determine size

categories as described above. For the

purposes of calculating the State

budgets, the following approach is used

to determine whether controls should be

assumed on a particular source for the

purposes of calculating the budget:

1. Use heat input capacity data for each

source if the data are in the updated

inventory.

2. If heat input capacity data are not

available, use the default identification of

small and large sources developed by EPA/

Pechan for OTAG and also used to develop

the NPR and SNPR budgets for source

categories with heat input capacity fields

(‘‘default data’’).

3. Emission reductions would be assumed

if specific source heat input capacity data or

default data indicate that a source is greater

than 250 mmBtu/hr in the updated

inventory.

4. If specific or default heat input capacity

data are not available in the updated

inventory (or not appropriate for a particular

source category), emission reductions would

be assumed if the unit’s average summer day

emissions are greater than one ton per day

based on the updated inventory.

5. All others are ‘‘small’’ and no emission

reductions are assumed.

c. Exemptions for Other Non-EGU

Point Sources.

Comments: Several comments

described source categories that might

be excluded from being assigned

assumed emissions decreases for

purposes of calculation of the NOX

budgets. In the NPR, EPA assumed a 70

percent reduction from large sources

and RACT on medium-sized sources.

Some commented that it is not possible

to control lime kilns and recovery

furnaces or that potential NOX

emissions reductions are very small.

One comment noted that recovery units

typically emit at a rate of 0.15 lb/mmBtu

or less and lime kilns at 0.20 lb/mmBtu

or less and suggested establishing an

emissions rate floor so that sources

emitting less than 0.15 lb/mmBtu (or

some other floor) would not need to

further control. Other commenters

suggested exempting cyclone boilers

less than 155 MWe and all aircraft

engine test facilities.

Response: The EPA agrees that for

purposes of today’s rulemaking the State

budgets should not reflect assumed

reductions in emissions from lime kilns,

recovery units and aircraft engine test

facilities. The amount of emissions from

these source categories is very small

relative to other point source categories

considered in this rulemaking. Further,

there is no experience in applying NOX

control technologies full scale to aircraft

engine test cells in the U.S. (EPA–453/

R–94–068, October 1994).

The EPA acknowledges that NOX

controls may be available at costs less

than $2,000 per ton for lime kilns,

recovery units and aircraft engine test

cells. However, these source categories

include a relatively small number of

sources with a small amount of

emissions. The EPA is concerned that

assuming controls on these sources for

purposes of State budgets would

encourage States to attempt to regulate

these sources. The EPA believes State

regulation could be inefficient because

of the relatively high administrative

costs of developing regulations for these

few source categories (particularly for

aircraft engine test cells because no

regulations have been developed for this

source category).

Similarly, EPA determined for each of

the following non-EGU point source

categories that the amount of emissions

are small relative to the total non-EGU

point source emissions and, thus, State

regulation could be inefficient because

of the relatively high administrative

costs of developing regulations for these

few source categories: ammonia,

ceramic clay, fiberglass, fluid catalytic

cracking, iron & steel, medical waste

incinerators, nitric acid, plastics, sand/

gravel, secondary aluminum, space

heaters, and miscellaneous fuel use

operations. Further, for many of these

categories the number of sources is

small and/or control technology

information is limited (e.g., where an

Alternative Control Techniques

document does not exist for that

category). The EPA believes that it

would be an inefficient approach to

suggest that States consider adopting

emissions reduction regulations for each

of these categories. Therefore, EPA did

not calculate emissions reductions from

these source categories for purposes of

calculating the budget.

At this stage in the process to reduce

regional transport, EPA considers it

most efficient to focus State and

administrative resources on the source

categories with greater amounts of

emissions. While States may choose to

control any mix of sources in response

to the SIP call, EPA is not, in today’s

rulemaking, assuming reductions from

these source categories as part of the

budget reduction calculation and does

not believe it is necessary for States to

do so.

It should be noted that EPA is

generally treating the non-EGU boilers/

turbines in the same manner as the

EGUs to enable States that opt into a

trading program to develop a simple and

effective trading program. Thus, the size

cutoffs discussed earlier in this section

are identical. Further, the regulatory

definition of a unit has been revised to

make it clear that only fossil-fuel fired

boilers and turbines are affected; this is

discussed in detail in the trading

program section later in today’s notice.

In addition, it should be noted that EPA

is not excluding reductions from

cyclone boilers, whether EGU or nonEGU, between 25–155 MWe from the

calculation of the State budgets in this

rulemaking. Such sources can be large

emitters of NOX and EPA expects the

control costs will be less than $2000/ton

on average through participation in the

emissions trading program.

d. Sources Without Adequate Control

Information.

Comments: As described in the SNPR,

there are many sources in the emissions

inventory which lack information EPA

would need to determine potentially

applicable control techniques. The

SNPR proposed to leave these sources in

the budget without assigning any

emissions reductions. The EPA received

comments that generally supported the

SNPR approach not to assign emissions

reductions to the diverse group of

sources where the Agency lacked

sufficient information to identify

potential control techniques (63 FR

25909).

Response: This group of sources is

diverse and does not fit within the

categories set out by EPA, but total

emissions are low for this group. The

EPA believes that the effort needed to

collect adequate information concerning

controls for those sources (about 6,000

small and 260 medium or large) would

be time consuming, the quality of the

information may be uncertain, and it

would potentially affect only a small

amount of NOX emissions. Therefore,

for purposes of today’s action, EPA

continues not to assume decreases in

emissions for these sources for purposes

of calculation of the State budgets, but

to keep them in the budgets at baseline

levels. In the future, as more

information becomes available, and if

additional NOX control is needed to

further reduce ozone transport, further
Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations 57417

consideration of these sources may be

necessary. Of course, States with

adequate information may choose to

control these sources to meet their

budgets.

e. Case-By-Case Analysis of Control

Measures.

Comments: Some commenters

suggested that EPA simply assume

reasonably available control technology

(RACT) for medium and, in some

comments, large sources in all upwind

States on a case-by-case basis and assure

that marginally stringent source-specific

reduction levels are rejected. Many

commenters stated that RACT default

levels used by EPA were not sufficiently

accurate and that case-by-case analysis

was needed because every industrial

source is different. Other comments

generally stated that control level

decisions should only be made on a

case-by-case basis because each affected

unit may have unique features that alter

its cost-effectiveness.

Response: In the final budget

calculation procedure EPA does not

calculate RACT requirements for

medium-sized sources. The assumption

of RACT or other controls on industrial

boilers and turbines between 100–250

mmBtu/hr would have been

inconsistent with EPA’s approach for

utility boilers and turbines, which

exempts units less than or equal to 250

mmBtu/hr. To be consistent with the

way EPA treats EGUs and because data

is often lacking for the smaller size

sources, EPA redefined ‘‘affected’’ nonEGU units to primarily include those

greater than 250 mmBtu. In cases where

heat input data are not available,

affected non-EGU units are those greater

than 1 ton per day; this level is also

consistent with the EGU cutoff because

it is approximately equivalent to the 250

mmBtu level. Consistency with the EGU

approach is important because it

provides equity, especially among the

smaller boilers and turbines and

simplifies the model trading program.

Therefore, the final rule does not

calculate budget reductions for the

medium size non-EGUs.

For the above reasons and as

described below, EPA has examined the

non-EGU sources on a category-bycategory basis and determined

appropriate control level assumptions

for the large units. There are several

reasons why EPA did not choose to

calculate the budget by examining

sources on a case-by-case basis. First,

such an approach would be inefficient

since all large sources would need to be

examined, rather than some source

categories being eliminated due to

category specific cost-effectiveness

limitations or amount of emissions.

Second, it would be very difficult for

the States to complete a case-by-case

analysis of their large sources, develop

rules, and respond to the SIP call within

the 12 month time frame (or the

statutory maximum 18 months). States

needed much more time to respond to

a similar requirement, the 1990 CAA

NOX RACT program. The CAA allowed

a 2-year period before the NOX RACT

rules were due from the States;

however, few States met this time frame

and several adopted generic RACT rules

which, in practice, resulted in much

longer time frames before the case-bycase RACT analyses were completed

and State rules adopted. Third, the

option of participating in a trading

program should mitigate cost impacts

on some sources that may have unique

configurations or other constraints.

Fourth, EPA has often issued standards

on a category-wide basis (e.g., New

Source Performance Standards) which

have proved workable even though

some individual units have higher costs

than the average. Fifth, the results of

such case-by-case analyses may not be

perceived to be as equitable as the

categorical approach because the control

levels resulting from the case-by-case

approach are likely to vary from sourceto-source and State-to-State. Finally, the

category-by-category approach selected

by EPA is preferred because it will

achieve air quality benefits sooner than

the case-by-case approach.

f. Cost-Effectiveness.

Comments: The EPA received

numerous comments on costeffectiveness. Those comments related

to uniform control levels or cost per air

quality improvement are addressed

elsewhere in this notice. Some

comments supported EPA’s proposed

$2,000 per ton approach. Some

commented that EPA should use

incremental costs, which are the costs

and reductions associated with

obtaining further control from a unit

that already has some level of controls

installed. Several commenters suggested

using marginal costs, defined as the cost

of the last ton of NOX removed by a

control strategy. Many stated that the

costs for non-EGUs should be no greater

than for utilities on a $/ton basis. One

commenter noted that non-EGU costs

will be considerably lower than EPA

estimates. One comment suggested that

EPA assume no further controls if the

source has BACT, LAER, MACT or

RACT already in place. One comment

supported a command-and-control

approach instead of the least cost for the

non-EGUs, and asserted that controlling

13,000 sources through this rulemaking

may not be feasible. Several commenters

suggested that CEMS costs for nonutilities should be included in the costeffectiveness determinations and that

alternative monitoring methodologies

should be considered.

Response: The EPA believes that the

approach of average cost-effectiveness

described in the proposal notices is

appropriate for this rulemaking. In

establishing the upper limit of the costper-ton range that EPA considers highly

cost-effective for this rulemaking, EPA

relied on average cost-effectiveness

values estimated for recently proposed

or promulgated rulemakings. The

marginal cost-effectiveness for the level

of control decided upon in the other

programs and rulemakings was not

always estimated or readily available.

The EPA’s latest assessment of costeffectiveness does account for the level

of existing or planned control in the

baseline case. Therefore, when EPA

refers to average cost-effectiveness it is

the average incremental cost between

the base and the more stringent level of

control.

For the non-EGU point sources, in the

NPR and SNPR EPA had aggregated the

non-EGUs as one group, which meant

that a few source categories with

relatively low costs and high percentage

emissions decreases dominated overall

average cost-effectiveness. For today’s

final action, EPA revised its approach

and analyzed individual source

categories to determine if control

techniques are available at average costs

less than $2,000 per ton. Further, EPA

included in this cost-effectiveness

approach the costs related to CEMS,

because this is a new and potentially

high cost to some of the non-EGU source

categories. As described in the RIA that

supports this final rulemaking, EPA’s

analysis determined that the following

non-EGU source category groupings

could achieve substantial emissions

decreases at average costs less than

$2,000 per ton: industrial boilers and

turbines, stationary internal combustion

engines, and cement manufacturing. As

further described in the RIA, controls

for sources grouped in the following

categories exceed $2,000 per ton: glass

manufacturing, process heaters, and

commercial and industrial incinerators.

The EPA believes that, over time,

costs for non-EGU point sources will be

lower than current EPA estimates;

however, the changes cannot be

quantified at this time. As discussed

below, EPA agrees that one source

category that has a NOX standard set

through the MACT process should not

be assumed to implement further

controls.

g. Industrial Boiler Control Costs.

Comments: Several comments were

submitted indicating that industrial
57418 Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations

boiler costs are generally higher than

utility boiler costs. The comments cited

factors of load variability, smaller size/

economies of scale, firing of multiple

fuels, and the ability to finance new

controls and pass on costs. Some

comments stated that most industrial

boilers are one-seventh the size of

utilities and, thus, EPA should

recognize that the costs of controls

would generally be higher due to

economies of scale.

Response: The EPA agrees that

industrial boiler sources are generally

smaller than utility boiler sources;

however, some individual industrial

sources are larger than some utility

sources. The EPA agrees that costs, on

average, to the industrial sector are

expected to be somewhat greater than

that expected by the utilities due, in

part, to economies of scale and the need

for CEMS (which are already in place at

utilities). Primarily due to the costs

related to continuous emissions

monitoring systems, EPA’s reanalysis of

cost-effectiveness for industrial boilers

resulted in a control level of 60 percent,

which is less stringent on average than

that for utilities.

h. Cement Manufacturing.

Comments: In the NPR, EPA proposed

a 70 percent control assumption on

large sources and RACT on medium

sources, including cement plants. Some

commenters suggested that cement

manufacturing should be excluded

because in the SIP Call area, there are

only a few cement plants and they have

low emissions. Several commenters

noted that many cement plants had

already implemented NOX RACT

controls. Some comments disagreed

with the costs and controls contained in

EPA’s Alternative Control Techniques

document (EPA–453/R–94–004, March

1994) and added that EPA should not

assume the same controls for different

types of cement plants. Several

commenters stated that 70 percent

control is not feasible and SCR costs

would be greater than $4,500 per ton,

but that 20–30 percent control is

possible. One commenter stated that the

SIP call would provide a major

competitive advantage to plants outside

the region, and that multi-plant

companies may shut down facilities

inside the SIP call region and increase

output at plants outside.

Response: Over 50 cement

manufacturing units together emit more

than twenty percent of emissions from

large point sources not in the trading

program (about 40,000 tons per season).

The EPA believes that the emissions

from this one industry are sufficiently

high that it is appropriate to examine

the availability of cost-effective controls.

The cost and control estimates in the

Alternative Control Techniques (ACT)

document were peer reviewed and, as

such, are considered by EPA as the best

data available. Consistent with the ACT

document for this industry, EPA

generally agrees with the commenters

that a 70 percent control level would

exceed the $2,000 per ton level used as

EPA’s cost-effectiveness framework.

But, with the evidence cited in the

cement ACT document and in some

comments, EPA believes that a 30

percent reduction from uncontrolled

levels would be within the costeffectiveness range for reducing

emissions at all types of cement

manufacturing facilities. Therefore, the

budget calculations assume a 30 percent

control level for this source category.

The EPA does not anticipate that, if

States were to choose to apply a 30

percent control level to cement plants,

this would be a major competitive

disadvantage for plants located in the

SIP call area because many cement

plants in the region have already

successfully implemented such controls

in State RACT programs.

i. Stationary Internal Combustion

Engines.

Comments: One comment suggested

EPA set RACT levels at 25 percent for

this category.

Response: As noted above, EPA is not

using a RACT approach in the final

rulemaking, but has examined each nonEGU point source category separately to

determine the maximum available

emissions reductions from controls that

would cost less than $2,000 per ton on

average. As described in the RIA, this

process of looking at source categories

individually resulted in EPA changing

the control level assumption for this

category from 70 percent in the NPR to

90 percent control in today’s final rule.

As described elsewhere in this notice,

EPA also changed the control level

assumptions for other source categories

through this more detailed approach.

For this source category, EPA

determined based on the relevant ACT

document, that post-combustion

controls are available that would

achieve a 90 percent reduction from

uncontrolled levels at costs well below

$2,000 per ton. (EPA–453/R–93–032,

1993.) Therefore, the budget

calculations include a 90 percent

decrease for this source category from

uncontrolled levels.

For spark ignited rich-burn engines,

non-selective catalytic reduction (NSCR)

provides the greatest NOx reduction of

all technologies considered in the ACT

document and is capable of providing a

90 to 98 percent reduction in NOX

emissions. The control technique for

spark ignited lean burn, diesel, and dual

fuel engines is selective catalytic

reduction (SCR). The SCR provides the

greatest NOX reduction of all

technologies considered in the ACT

document for these engines and is

capable of providing a 90 percent

reduction in NOX emissions.

j. Industrial Boilers and Turbines.

Comments: Several commenters

indicated that boilers using SNCR may

achieve 40–60 percent reduction, but

not 70 percent. Other comments

supported the 70 percent control level

proposed.

Response: The EPA examined the

category of industrial boilers and

turbines to determine the largest

emissions reductions that would result

from controls costing less than $2,000

per ton on average, including costs

related to CEM systems. As described in

the RIA, for this source category, EPA

determined that controls, including SCR

and SNCR, are available that would

achieve a 60 percent reduction from

uncontrolled levels at costs less than

$2,000 per ton on average. For those

sources that participate in the trading

program, EPA believes that the costs

would be further reduced. Therefore,

the budget calculations include a 60

percent reduction for this source

category from uncontrolled levels.

k. Municipal Waste Combustors

(MWCs).

Comments: Several comments

suggested that State budgets should not

reflect emissions decreases for MWCs

beyond those already required by the

MACT rules.

Response: The NPR did not assume

reductions for MWCs in the calculation

of the budgets. However, since MACT

reductions are required, and will be

achieved well before 2007, those

reductions should be accounted for in

the 2007 baseline emissions inventory.

The EPA agrees that additional

emissions decreases beyond MACT

levels are not warranted for this source

category at this time because they would

exceed the $2,000 per ton framework for

highly cost-effective controls. Therefore,

EPA has incorporated the NOX

emissions decreases due to the MACT

requirements into the 2007 baseline

levels and not assume any further

reductions.

D. Highway Mobile Sources

Background: For the NPR and SNPR,

highway vehicle emissions were

projected to 2007 from a base year of

1990. The NPR used the 1990 OTAG

inventory as its baseline. The 1990

OTAG inventory was based on actual

1990 vehicle-miles-traveled (VMT)

levels for each State, based on State
Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations 57419

60Both MOBILE5a and MOBILE5b are official

EPA models. States can use either model in their

SIPs, provided they use the corrected default inputs

with MOBILE5a. For the control programs

evaluated in today’s action, MOBILE5a with

corrected default inputs gives the same emission

estimates as MOBILE5b. Because both models are

considered valid by EPA and give the same

emission estimates, the EPA has determined that

the choice of which model to use in calculating

highway vehicle emission budget components is a

matter of convenience. The EPA has chosen to

retain the use of MOBILE5a for today’s action in

order to maintain consistency with the OTAG

process, in which MOBILE5a with corrected default

inputs was used to construct its highway vehicle

emission inventories and to calculate the

effectiveness of highway vehicle emission control

options.

submittals to OTAG where available, or

on historical VMT data obtained from

the Highway Performance Monitoring

System (HPMS) if State data were not

available. The EPA proposed to switch

to historical 1995 VMT levels from the

HPMS; States were encouraged to

submit their own 1995 VMT estimates

where those estimates differed from

HPMS.

In today’s notice, EPA has

implemented the changes it proposed in

the NPR in calculating baseline and

projected future NOX emissions from

highway vehicles. A 1995 baseline is

used for today’s notice in place of the

1990 baseline used in the NPR. The

HPMS data were used to estimate States’

1995 VMT by vehicle category, except

in those cases where EPA accepted

revisions per the comments. These VMT

estimates reflect the growth in overall

VMT from 1990 to 1995, as well as the

increase in light truck and sport-utility

vehicle use relative to light-duty vehicle

use. The 1995 NOX emissions

inventories also reflect the type and

extent of inspection and maintenance

programs in effect as of that year and the

extent of the Federal reformulated

gasoline program. The EPA is

continuing to use the growth factors

developed by OTAG for the purpose of

projecting VMT growth between 1995

and 2007. These growth factors were

revised with appropriately explained

and documented growth estimates

submitted during the comment period

for the NPR.

The 2007 highway vehicle budget

components presented in today’s notice

are based on EPA’s MOBILE5a emission

inventory model with corrected default

inputs, which represents the most

current EPA modeling guidance to

States when developing their SIPs.60

1. Base Inventory

Comment: The EPA received a

number of comments on baseline

highway vehicle emission inventories.

Most of these commenters proposed

changes to baseline VMT estimates or to

control factors related to highway

vehicle emissions.

Response: In the NPR and SNPR, EPA

asked commenters to provide

sufficiently detailed information to

permit revision to county-level emission

inventories, in order to allow airshed

modeling to be performed using the

revised inventories. A number of

proposed VMT revisions submitted by

commenters were not sufficiently

detailed to permit county-level

inventory revisions and therefore these

revisions were rejected. Other

commenters provided sufficiently

detailed data, which were incorporated

into the base year VMT inventory, with

two exceptions. Two States submitted

1995 VMT estimates that were

inconsistent with EPA and U.S.

Department of Transportation

information on the relative contribution

of light-duty trucks to total VMT. The

EPA chose to use the HPMS default data

for these two States.

Comment: One commenter asked the

EPA to use VMT from the 1996 Periodic

Emissions Inventory (PEI) or 1996

National Emissions Trends (NET), rather

than 1995 Highway Performance

Modeling System (HPMS) data when

calculating baseline inventories. Several

other commenters supported EPA’s use

of 1995 HPMS data to calculate baseline

VMT inventories.

Response: Guidance on how to

construct the 1996 PEI was not released

until July 1998 and State PEI submittals

are not expected until 1999. The EPA

has determined for this reason that the

1996 PEI is not suitable for calculating

the baseline VMT inventory. The EPA

considered using 1996 NET VMT data

in its base inventories, but those data

were based on estimated 1995 HPMS

inputs. The EPA has chosen to use the

actual 1995 HPMS data rather than

estimates in order to reduce the

uncertainties associated with estimating

baseline and 2007 emission inventories.

Comment: One commenter suggested

using a multi-year VMT activity average

to establish the highway emission

baselines to smooth out abnormal

patterns, instead of relying solely on

1995 activity.

Response: The EPA proposed using

1995 VMT in order to shorten the time

period over which VMT growth would

have to be projected. The EPA is not

aware of any evidence that suggests that

1995 was an abnormal year in terms of

VMT activity. Furthermore, States did

not submit multi-year VMT averages in

response to the EPA’s invitation to

submit their own VMT data. If the EPA

were to construct multi-year averages, it

is not clear what time frame would be

appropriate. The EPA believes that the

uncertainty related to having to project

VMT growth estimates over a longer

time period is at least as great as the

uncertainty related to the

representativeness of 1995 VMT. For

these reasons, EPA has chosen to use

1995 VMT for base year and projection

year inventories.

Comment: A number of commenters

raised various issues about the use of

the MOBILE5 emission factor model for

this analysis. Most of these comments

focused on specific assumptions or

estimates incorporated in MOBILE5

which may need to be modified or

updated to account for new information.

Response: The EPA is currently

developing an updated emission factor

model called MOBILE6. When final, this

model will supersede the MOBILE5

model used by the EPA to develop

baseline and 2007 emission inventories

and States’ highway vehicle budget

components. The concerns raised by

commenters are being evaluated as part

of the MOBILE6 development process.

At the present time, however, MOBILE5

remains EPA’s official emission factor

model. The EPA currently is not able to

determine whether the highway vehicle

emission modeling concerns raised by

commenters are valid or whether the

changes they suggest would raise or

lower emission estimates; EPA is also

not able to quantify the effects of

commenters’ concerns using its current

emission models. Some of the changes

EPA expects to make in its next official

emission factor model, such as the

effects of aggressive driving and air

conditioner use, are likely to raise

emission estimates; others, such as lessrapid deterioration of emissions

performance than previously forecast,

are likely to lower emission estimates.

Because the overall effect of these and

other changes cannot yet be determined,

the EPA has chosen to continue using

its current official emission model in

today’s action.

As discussed in Section III.F.5, the

budgets presented in today’s action

serve as a tool for projecting in advance

whether States have adopted measures

that would produce the required

amount of emissions reductions, as

indicated by the initial demonstration

submitted in September 1999. The

budgets are also a means for

determining from 2003 to 2007 whether

States are fully implementing those

measures. Thus, the budgets are an

accounting mechanism for ensuring that

the upwind States have adopted and

implemented control measures that

prohibit the significant amounts of NOX

emissions targeted by section

110(a)(2)(D)(i)(I). Although EPA’s
57420 Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations

projections of emissions from highway

vehicles will change as the Agency

improves its emission models, these

changes will not in and of themselves

require changes in the actions States

undertake to reduce ozone transport

under today’s action.

2. Growth

Comments: The EPA received

numerous comments concerning its

projection of States’ 2007 highway

vehicle budget components. In addition

to the changes in baseline VMT

discussed previously in Section III.D.1

of this notice, the EPA received from a

number of States proposed revisions to

VMT growth estimates and the

effectiveness of emission control

programs.

Response: In today’s action, EPA has

implemented the following changes it

proposed in the NPR in calculating

States’ 2007 highway vehicle budget

components. The EPA has used State

projections of VMT growth from 1995

through 2007 for States that submitted

appropriately explained projections of

VMT growth from 1995 to 2007. For

other States, EPA projected 2007 VMT

levels from the 1995 baseline VMT

levels using the OTAG projected growth

rates.

As proposed in the NPR, neither the

highway vehicle budget components nor

the overall NOX budgets promulgated in

today’s action alter the existing

conformity process or existing SIPs’

motor vehicle emissions budgets under

the conformity rule. The EPA has

determined that Federal agencies or

Metropolitan Planning Organizations

(MPOs) operating in States subject to

today’s action do not have to

demonstrate conformity to the SIP Call

budgets or the highway vehicle budget

component levels used to calculate the

budgets. However, areas will be

required to conform to the motor vehicle

emissions budgets contained in the

attainment SIPs for the new eight-hour

standard. For their attainment SIPs for

transitional ozone nonattainment areas,

States might seek to rely on the

modeling performed for the SIPs

submitted in response to today’s action.

To the extent that this occurs, the VMT

projections and motor vehicle emissions

inventories associated with today’s

action could have a role in the

conformity process, beginning when

transitional areas are designated and

classified in 2000.

3. Budget Calculation

Background: The EPA proposed

highway budget components based on

projected highway vehicle emissions in

2007 from a base year of 1990, assuming

implementation of CAA measures, such

as inspection and maintenance

programs and reformulated fuels,

measures already implemented

federally, and those additional measures

expected to be implemented federally

by 2007. The additional Federal

measures included the National Low

Emission Vehicle Standards and the

2004 Heavy-Duty Engine Standards. The

emission effects of revisions to the

Federal Emissions Test Procedure,

which had also been promulgated in

final form, were not reflected in the

projected 2007 emissions presented in

the proposal because neither the

emissions that this measure is designed

to control nor the reductions in those

emissions expected from the test

procedure revisions had been

incorporated in the projected 2007

emission estimates or in peer- and

stakeholder-reviewed EPA emission

models. The proposal also did not

incorporate any benefits from Tier 2

light-duty vehicle standards since the

EPA had not yet proposed or

promulgated regulations concerning the

level and implementation schedule for

Tier 2 standards. Seasonal emissions

were calculated by estimating emissions

for a specific weekday, Saturday and

Sunday during the ozone season and

multiplying by the number of days of

each type in the ozone season. These

estimates were based on temperatures

and temperature ranges recorded for

actual ozone episodes. In the NPR, EPA

proposed to change this approach to

substitute monthly average temperatures

and temperature ranges for ozone

episode-specific temperatures when

constructing the 2007 budgets. The

highway vehicle budget components

presented in today’s notice reflects this

change.

Comment: A number of commenters

suggested that the EPA change its

assumptions regarding emission control

programs from those used in the NPR.

One commenter claimed that the NPR

did not include a number of costeffective highway and nonroad mobile

source NOX reduction programs in its

budget calculations. Other commenters

suggested that the EPA focus more on

expanding the RFG and I/M programs,

adopting gasoline sulfur controls,

implementing a reformulated diesel fuel

program, or implementing the Tier 2

program. Contrary to these positions, a

number of commenters agreed with the

EPA’s decision not to assume any

expansion of the RFG or I/M programs,

while still other commenters argued that

the EPA should not include the

emission effects of gasoline sulfur

controls or reformulated diesel fuel in

its calculation of State NOX budgets.

One commenter suggested that the EPA

change its NLEV phase-in assumptions

to match the final NLEV agreement. One

commenter asked EPA to include the

effect of the recent Revised Federal Test

Procedure rule, which is aimed at

reducing excess emissions from

aggressive driving or air-conditioner

use, in its budget calculation.

Response: Both the NPR and today’s

action include those mobile source

reductions which EPA has determined

or proposed to determine are

technologically feasible, highly costeffective, and appropriate to implement

on a national basis, and which have

been promulgated in final form or are

expected to be promulgated in final

form before States are required to

submit revised SIPs. The highway

vehicle budget components include the

emission reductions resulting from

implementation of the NLEV program,

including the phase-in schedule agreed

to by the States, automobile

manufacturers, and EPA. The highway

budget components do not include the

effect of Tier 2 light-duty vehicle and

truck standards and any associated fuel

standards since these standards have

not yet been proposed.

The extent of the RFG and I/M

programs was not assumed to change

beyond that assumed for the NPR,

except for those States who were able to

demonstrate that the NPR’s modeling

assumptions did not conform to the

State’s SIP and did not reflect CAA

requirements. As discussed elsewhere

in today’s notice and in the NPR, the

NOX reductions alone from these

measures do not appear to be highly

cost effective in all of the areas that

would be subject to reduced budgets.

Because these measures offer additional

benefits beyond NOX reductions,

specific local areas may determine that

these measures are appropriate and cost

effective given their full range of

benefits.

The baseline and budget calculations

include neither the increased emissions

from aggressive driving or air

conditioner use, nor the reductions in

those emissions resulting from the

Revised Federal Test Procedure rule.

These emission effects are not reflected

in EPA’s MOBILE5a model; they are

being evaluated for inclusion in

MOBILE6. While the EPA has

developed a modified version of its

MOBILE5 model to estimate these

effects for its Tier 2 study, this modified

model has not been used in any

regulatory actions and is still subject to

revision as part of EPA’s model

development process. As discussed

above and in Section III.F.5. below, any
Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations 57421

changes by EPA in its emission models

will not in and of themselves alter the

emission reductions States must achieve

to comply with the requirements of

today’s action.

Comment: One commenter suggested

that the EPA not split VMT using

weekend and weekday travel fractions

when calculating monthly and seasonal

total VMT. Another State commenter

proposed an alternative method for

calculating monthly and seasonal VMT

from average daily VMT which did not

rely on the EPA weekend/weekday

travel fractions, but instead used

monthly travel fractions specific to that

State. Other commenters supported the

weekend/weekday inventory modeling

approach proposed by the EPA.

Response: The EPA and other

organizations have amassed

considerable evidence that weekend and

weekday travel patterns differ

significantly. The OTAG Final Report

requested day-specific inventories for

developing day-of-the-week activity

levels used in emission inventory

development and episode-specific

modeling. Given this requirement, EPA

has determined that the approach

outlined in the NPR is appropriate and

reasonable. The alternative method

using State-specific monthly travel

fractions as proposed by one State is a

reasonable alternative. However,

because EPA does not have the

necessary information to apply this

method to all other States, EPA did not

incorporate this method in its analysis.

a. I/M Program Coverage.

Comment: One commenter urged the

EPA to expand I/M programs to cover

all urbanized areas with populations

above 500,000 as recommended by

OTAG. Other commenters also

requested that EPA expand the I/M

program or require specific States to

adopt specific types of I/M programs. By

contrast, other commenters supported

the I/M approach taken by the EPA in

the NPR.

Response: The OTAG recommended

that States consider expanding I/M

programs to cover all urbanized areas

with populations above 500,000. The

EPA has considered this

recommendation but does not believe it

to be appropriate to assume broader

I/M implementation in calculating State

budgets for the reasons outlined in the

NPR (62 FR 60355). The State budgets

promulgated in today’s action reflect

full implementation of I/M as required

by the CAA and State SIPs.

b. Emissions Cap.

Comment: One commenter suggested

that the EPA consider capping mobile

source emissions, arguing that the

proposed rule would place an undue

burden on stationary sources.

Response: The State NOX budgets

promulgated in today’s action include

the projected emission benefits of those

NOX controls that the EPA has

determined are technologically feasible

and highly cost effective, as well as

additional controls whose

implementation is not dependent on

this rule. While the EPA’s analysis

indicates that certain categories of

stationary sources offer the potential for

large, highly cost-effective NOX

emission reductions, the State NOX

budgets also reflect the emission effects

of a number of mobile source controls

(See Table IV–2). The EPA believes that

it has applied its criteria for determining

which controls to assume in State NOX

budgets equitably to both mobile and

stationary sources. In contrast to EGUs

and large non-EGUs, EPA has not

concluded that a mass cap (which

would effectively require offsets for

VMT growth) is highly cost effective.

For these reasons, EPA does not believe

that today’s action places an undue

burden on any emission sector and does

not believe that a separate cap on

mobile source emissions is necessary.

c. Tier 2 Standards.

Comment: One commenter requested

that EPA include the effects of Tier 2

light-duty vehicle standards when

calculating State budgets if the NLEV

program fails. Another commenter

suggested that States not be permitted to

adjust their budgets in case the NLEV

program fails.

Response: This issue is not yet ‘‘ripe’’

because NLEV is currently being

implemented and there are no signs that

the program will fail. The EPA will

consider whether to adjust State budgets

if automakers representing a significant

portion of new vehicle sales withdraw

from the NLEV program, as discussed in

Section III.F.5.

d. Low Sulfur Fuel.

Comment: One commenter stated that

the EPA disregarded OTAG’s call for

reducing sulfur levels in fuel, which

would have the effect of reducing NOX

emissions.

Response: The EPA’s proposed rule

and other actions match the OTAG

recommendations on fuels, contrary to

the commenter’s suggestion. The OTAG

gasoline recommendation stated, ‘‘The

USEPA should adopt and implement by

rule an appropriate sulfur standard to

further reduce emissions and assist the

vehicle technology/fuel system [to]

achieve maximum long term

performance.’’ It did not request that

EPA implement a specific sulfur

reduction proposal. The EPA is

evaluating the costs and benefits of

reducing gasoline sulfur levels as part of

its proposed rulemaking to implement

Tier 2 light-duty vehicle and truck

standards. The EPA is also evaluating

the relationship between diesel fuel

standards and the emission standards as

part of (i) its 1999 technology review for

its 2004 highway heavy-duty diesel

engine standards and (ii) its 2001

technology review for the Tier 3 and

Tier 2 nonroad diesel engine standards.

Until these evaluations are complete,

EPA believes it is premature to assume

any changes in fuel properties when

calculating States’ highway vehicle

budget components.

e. Conformity.

Comment: One commenter

recommended that NOX transportation

conformity waivers should lapse in the

wake of today’s action.

Response: Conformity waivers were

granted on an area-by-area basis, given

the facts of the situation in each local

area. Any withdrawal should be based

on similar local analysis, or upon

submittal of a valid attainment plan.

Today’s action is not based on this kind

of local analysis. Thus, there is no basis

for any withdrawal of existing NOX

transportation conformity waivers.

Furthermore, any such withdrawal

would not alter the Statewide NOX

budgets set forth in today’s action. For

these reasons, the EPA has concluded

that today’s action does not alter

existing conformity requirements,

including any NOX conformity waivers.

Comment: One commenter expressed

concern that if current conformity

budgets do not incorporate the same

control assumptions as the States’

budgets submitted in response to

today’s rulemaking, the growth in areas

currently subject to conformity budgets

could threaten the ability of States to

meet the SIP call budgets. The

commenter continued that failure to tie

conformity budgets to transport budgets

would allow these areas to grow to preSIP call control budget levels that could

cause an exceedance of the Statewide

budget. The commenter also stated that

to address local ozone problems,

transportation conformity plans should

reflect the mobile source controls

assumed in the SIP call.

Response: Conformity budgets cannot

be tied directly to the SIP Call budgets

because the latter are statewide and the

former are nonattainment-area-specific.

The Statewide NOX budgets will be

enforced as described in today’s action,

regardless of the conformity budgets in

specific areas within the affected States.

These budgets should reflect the actual

level of motor vehicle emissions which

States expect to occur.
57422 Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations

As noted elsewhere in this section,

conformity budgets will reflect the

mobile source controls assumed in the

SIP Call budgets to the extent that the

attainment SIP ultimately relies upon

those controls. Today’s action does not

change the rules governing generation

and use of emission reduction credits to

offset further growth in the

transportation sector as part of a local

area’s conformity demonstration.

E. Stationary Area and Nonroad Mobile

Sources

Background: The EPA developed the

NOX SIP call emissions inventory for

area and nonroad mobile sources based

on data sets originating with the OTAG

1990 base year inventory. These base

year inventories were prepared with

1990 State ozone SIP emission

inventories supplemented with either

State inventory data, if available, or

EPA’s National Emission Trends (NET)

data if State data were not available. The

OTAG 1990 nonroad emission

inventories were based primarily on

estimates of actual 1990 nonroad

activity levels found in the October

1995 edition of EPA’s annual report,

‘‘National Air Pollutant Emission

Trends.’’ In the NPR, EPA proposed

switching to EPA’s 1997 ‘‘Trends’’

estimate of 1995 nonroad activity levels.

For the SNPR, area and nonroad

mobile source inventory data for 1990

were then grown to 1995 using Bureau

of Economic Analysis (BEA) historical

growth estimates of industrial earnings

at the State 2-digit Standard Industrial

Classification (SIC) level. Because BEA

data are historical documentation of

industry earnings, EPA considered these

to be among the best available indicators

of growth between 1990 and 1995 (63

FR 25915). Once the common base year

of 1995 was established for these source

categories, BEA growth assumptions

utilized by OTAG were used to estimate

the 2007 base case inventory.

1. Base Inventory

Comment: The EPA received several

comments on baseline area and nonroad

mobile source emission inventories.

Several commenters submitted

estimates of their 1990 nonroad activity

levels that differed from NPR estimates.

One commenter provided statewide

2007 base year emissions estimates for

numerous area source categories, while

others provided similar information for

1990 or 1995 emission estimates. Many

commenters expressed concern with

existing area source inventory estimates

and provided revised county-level area

source inventories. One commenter

suggested using a multi-year activity

average to establish the nonroad

emission baseline, arguing that a multiyear average would provide a more

representative baseline than would a

single year’s data alone.

Response: In the NPR and SNPR, EPA

asked commenters to provide

sufficiently detailed information to

permit revision to county-level emission

inventories, in order to allow airshed

modeling to be performed using the

revised inventories. Some proposed area

and nonroad inventory revisions

submitted by commenters were Statewide revisions and did not contain

sufficient detail to permit the EPA to

revise county-level nonroad emission

inventories. Because the EPA could not

use these submittals to revise the

county-level inventories used as inputs

to its air quality modeling analyses,

these submittals were not accepted.

Other commenters did provide

sufficiently detailed data, and EPA

revised the appropriate emission

inventories to reflect the commenters’

estimates. These revised inventories

were then grown to 1995 using BEAderived growth factors, as described

above.

Although EPA proposed in the NPR to

switch to a 1995 inventory in

calculating baseline NOX emissions

from nonroad mobile sources, EPA has

chosen not to do so in today’s action.

Using the 1995 inventory presented in

the ‘‘Trends’’ report as the baseline for

today’s action would have required the

use of geographic allocation methods

that have not undergone peer review

and have not been made available for

public comment by affected interests.

The EPA has concluded that the use of

these unreviewed methods in today’s

action would have deprived

stakeholders of adequate opportunity to

review, understand, and comment on

their baseline inventories and the

methods used to construct them. Hence,

EPA has chosen to retain the 1990

baseline inventories for nonroad mobile

sources presented in the NPR for today’s

action, with the changes made in

response to comments.

As discussed above, EPA has chosen

to use 1990 nonroad activity level

estimates as the basis for its nonroad

inventory projections. The EPA is not

aware of any evidence that suggests that

1990 was an abnormal year in terms of

nonroad activity. Furthermore, States

did not submit multi-year nonroad

activity averages in response to EPA’s

invitation to submit their own nonroad

activity data. If EPA were to construct

multi-year averages, it is not clear what

time frame would be appropriate. To

reduce the impact of unusual years, EPA

would have to take a long-term average.

However, doing so would require EPA

to use an even earlier year as its base

year for nonroad activity and inventory

projections. The EPA believes that the

uncertainty related to having to project

nonroad activity growth estimates over

a longer time period is at least as great

as the uncertainty related to the

representativeness of 1990 nonroad

activity.

2. Growth

Comment: Several commenters

suggest that the growth factors used to

determine 2007 stationary area and

nonroad mobile source base year

inventories are inaccurate or

inconsistent across regions and

categories of the inventory. They

explained that if growth factors are to be

used to estimate future base year

emissions, consistent national or regionwide values should be utilized for all

categories across all States within the

domain. This, they continue, would

promote equitable potential progress to

all areas and not penalize those that

have shown past poor growth rates.

Some commenters go on to state that

growth rates based on past growth

automatically disadvantage States

which have suffered from unusually low

growth rates. In addition to growth

rates, some commenters provided 2007

base year emission estimates either with

or without the growth and control

information needed to validate their

calculation.

Response: As noted above, EPA relied

on BEA State-specific historical growth

estimates of industrial earnings at the 2-

digit SIC level as among the best

available indicators of growth for

stationary and nonroad area sources.

BEA projection factors assume the

continuance of past economic

relationships. These factors are

published every five years and adjusted

to account for recent production and

growth trends. For this reason, BEA data

provide a useful set of regional growth

data that EPA recommends for use in

preparing emission inventory

projections. It is true that BEA

projection factors differ among different

areas and different source categories

because of historical differences in

industrial growth among those different

areas and source categories. However, in

general, these projection factors offer the

most reliable indicators of future growth

as are available.

In cases where commenters

questioned the use of EPA’s growth

rates but provided no alternative of their

own, EPA had little choice but to

continue to use the BEA-derived growth

rates. Some commenters provided

alternative or supporting information for

modification of source category or State
Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations 57423

growth estimates. In those cases where

a State or industry may have had more

accurate information than the BEA

forecast (e.g., planned expansion or

population rates), data were verified and

validated by the affected States and by

EPA, and revisions were made to the

factors used for that category.

3. Budget Calculation

Background: The EPA proposed

nonroad mobile source budget

components based on projected nonroad

mobile source emissions in 2007 from a

base year of 1990. These projections

were developed by estimating the

emissions expected in 2007 from all

nonroad engines, assuming

implementation of those measures

incorporated in existing SIPs, measures

already implemented federally, and

those additional measures expected to

be implemented federally. The

additional Federal measures include:

the Federal Small Engine Standards,

Phase II; Federal Marine Engine

Standards (for diesel engines of greater

than 50 horsepower); Federal

Locomotive Standards; and the Nonroad

Diesel Engine Standards. In the NPR,

EPA used the estimates developed by

the OTAG for nonroad mobile source

baseline emissions and growth rates.

Comments: The EPA received

comments to use a State-specific set of

growth rates for nonroad mobile source

emissions.

Response: The EPA has used State

estimates of 1990 nonroad activity

levels and growth rates for 1990 through

2007 received during the comment

period to revise its estimates of nonroad

NOX emissions in 2007, where those

State estimates were appropriately

explained and documented. For other

States, the EPA has retained the baseline

activity levels and growth rates used in

the NPR, which in turn were based on

the growth rates developed for OTAG.

F. Other Budget Issues

1. Uniform vs. Regional Controls

Background: In the NPR, EPA bases

the State budgets upon assumed

application of reasonable, highly costeffective NOX control measures. These

measures were uniform across the 23

affected jurisdictions. They consisted of

0.15 lbs/MmBtu for the EGU sector; and

70 percent control for large, and RACT

for medium-sized, non-EGU point

sources.

Comments: A number of commenters

opposed calculating budgets based on

uniform emissions reductions and cited

the fact that OTAG recommended a

range of control levels. These

commenters offered no specific

alternatives, such as varying the

assumed control levels by State or by

groups of States, or alternative methods

for determining different control levels.

Numerous comments were received

supporting the proposed uniform level

of emissions reductions.

Response: The EPA has determined

that each of the 23 jurisdictions has

sources that emit NOX in amounts that

significantly contribute to downwind

nonattainment problems. Moreover,

EPA has determined that specified

levels of control on certain sources in all

of the jurisdictions would be highly

cost-effective. This analysis applies with

equal force to each of the 23

jurisdictions. It may be that emissions

from some States have greater ambient

impact on downwind nonattainment

areas than emissions from more distant

States. Even so, each of the States’ NOX

emissions have a sufficient ambient

impact downwind to conclude that

those amounts are significant

contributions and that NOX emissions

from all the upwind jurisdictions

collectively contribute significantly to

nonattainment downwind.

Differentiating the contributions of

individual upwind States on multiple

downwind nonattainment areas is a

highly complex task. The contributions

of individual States are likely to vary

from downwind area to downwind area,

from episode to episode, and from

NAAQS to NAAQS. Accordingly, it

would be extremely complex to develop

a budget for each State that would

reflect the different impacts of its

sources’ emissions on different

downwind States.

Among many factors that EPA

considered in weighing whether to

finalize a uniform control level or

regional control levels in calculating

States’ emission budgets was the

concern that different controls in one

part of the SIP call area in combination

with an interstate emissions trading

program may lead to increases in

pollution within areas having more

restrictive controls. That is, if

unrestricted interstate emissions trading

were allowed on an one-for-one basis,

emissions reductions might be expected

to shift away from States assigned more

restrictive controls to States which

received less restrictive control

requirements due to the lower control

costs likely to exist in States with less

restrictive controls. This may result in

emissions above the budget level in

areas with more restrictive controls.

There are two alternatives for

addressing the problem of shifting

emissions. The first is to allow trading

only within uniform control regions, but

not between regions with NOX budgets

reflecting different levels of control. The

advantage to this approach is that it

provides a straightforward way of

preventing trades of excess emissions

into regions with more stringent

standards. However, a trading program

that covers a smaller market area will

provide less flexibility and reduce the

possible savings for the affected sources

as compared with larger trading

programs. The second alternative is to

establish a trading ratio for trades

between regions, to reflect the

differential impact of the emissions on

nonattainment. The trading ratio should

reflect the relative contribution of

emissions to downwind non-attainment

problems. The advantage to this

approach is that it provides the

flexibility for trades between regions

when the benefits of such trades are

large, while discouraging a shift of

excess emissions into regions with more

stringent standards. However, none of

the comments on the proposal included

a justification or description for trading

ratios, which would reflect the

differential environmental implications

and discourage inappropriate shifting of

excess emissions.

The ozone problem in the Eastern

United States is the result of a large

number of different types of sources

which affect widely distributed

nonattainment areas at different times

under changing weather patterns such

that a broadly-established control

program is necessary. The EPA believes

a reasonable strategy is to apply the

most cost-effective control strategies

uniformly in contributing States in

order to eliminate the combined

significant contribution from these

multiple sources in multiple States.

The EPA analyzed costs and air

quality benefits for two regional control

level options that were based on a

varying level of controls in different

parts of the 23 jurisdictions. The

analysis did not show that these two

regional control alternatives would

provide either a significant

improvement in air quality or a

substantial reduction in cost. An

analysis of the costs and benefits of

different control options can be found in

the docket. On the basis of the analysis,

EPA believes an alternative approach

with differentiated NOX budgets and

regionally differentiated trading would

not yield significant additional air

quality benefits or cost savings vis a vis

a regionwide trading program based on

uniform NOX budgets.

2. Seasonal vs. Annual Controls

Comments: One commenter suggested

that controls should be required for the
57424 Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations

entire year rather than just during the 5-

month ozone season as proposed.

Response: The EPA recognizes that

control of nitrogen oxide emissions

would likely produce non-ozone

benefits, as well as ozone benefits. For

example, NOX control would likely

reduce surface water acidification or

eutrophication of surface waters.

Annual control of NOX may have a

greater impact on winter and spring

NOX emissions, and therefore on

acidification and eutrophication, than

ozone season (summer) NOX control to

the extent that acidification and

eutrophication result from the release of

nitrogen compounds from snowpack

during snowmelt and rain in the spring.

Control of NOX emissions also reduces

fine particulates and regional haze, so

that annual control of NOX emissions

would result in greater non-ozone

benefits. However, the commenter’s

suggestion that EPA analyze the costs of,

and assume in calculating the budgets,

annual NOX control to address nonozone problems is outside the scope of

this rulemaking proceeding. Here, EPA

has proposed a NOX SIP call to address

the failure of certain SIPs to prohibit

sources from emitting NOX in amounts

that contribute significantly to

nonattainment (or interfere with

maintenance of attainment) of the ozone

NAAQS during the ozone season.

In analyzing the benefits of ozone

season NOX control under the proposed

NOX SIP call for purposes of the RIA

(though not as a basis for the decisions

in today’s rule), EPA considered both

the ozone and non-ozone benefits. Nonozone benefits include the impact of

ozone season NOX control on

acidification and eutrophication. In

particular, emission modeling

performed by EPA indicates that the SIP

Call would reduce wintertime NOX

emissions. This results in part because,

once installed to comply with the NOX

SIP call, some NOX control systems

(e.g., low NOX burners which alter the

combustion process and cannot simply

be turned off) would reduce emissions

throughout the year, even though the

NOX limits would be seasonal. Also see

Section IX.

3. Full vs. Partial States

Background: In the NPR, the Agency

indicated it was proposing to include

entire States rather than exempting

portions of States in the development of

emissions budgets. The Agency’s

decision to include full States was based

upon three major points: (1) The

division of individual States by OTAG

was based, in part, on computational

limitations in OTAG’s modeling

analyses; (2) the additional upwind

emissions from full, as opposed to

partial, States would provide additional

benefit to downwind nonattainment

areas; and, (3) Statewide emissions

budgets create fewer administrative

difficulties than a partial-State budget.

Comments: During the two comment

periods, 43 comments were received

which specifically addressed some or all

of the major points outlined above. The

underlying theme throughout the

comments on this issue was that the

States and EPA had undertaken a

comprehensive, scientifically credible

modeling/analysis study during the

OTAG, and that the Agency should

follow OTAG’s recommendations on

this issue (i.e., allow for partial-State

emission budgets). Another common

theme was that the administrative

difficulties outlined by the Agency in

the NPR were exaggerated, and that the

affected States should be allowed to

generate partial-State, as opposed to

statewide, emissions budgets, if their

State considered it feasible to do so.

Comments were received that portions

of Alabama, Georgia, Michigan,

Missouri, North Carolina, and

Wisconsin should be excluded from the

SIP Call.

Response: The underlying concepts

for responding to these comments are (a)

that the atmosphere is constantly in

motion and has no limitations at geopolitical boundaries, and (b) that the

larger the geographic area that is

controlled, the greater the downwind

benefits. For the States requesting

partial-State emissions budgets, there

are NOX emissions throughout these

entire States. The EPA did State-specific

modeling for each of the affected States,

and these additional modeling analyses

support the concept of statewide

emissions budgets for each of the

affected States. Furthermore, it is a

reasonable assumption, given the nature

of ozone chemistry, that if emissions

from part of a State contribute

significantly to downwind

nonattainment or maintenance

problems, emissions from the entire

State contribute significantly to

downwind nonattainment or

maintenance problems. In each of the

affected States, there is no peculiar

meteorological phenomenon that would

indicate that emissions from some

portion of that State would not impact

downwind nonattainment or

maintenance problems. Thus, based on

additional EPA modeling analyses and

their technical interpretation, EPA is not

promulgating partial-State emissions

budgets. Since each State has the

flexibility to determine which sources to

control in order to meet the budget, a

State can structure its control strategy to

require fewer reductions in certain

portions of the State and greater controls

in other areas, as long as the significant

amounts of emissions are eliminated.

4. NOX Waivers

Comments: The EPA received several

comments supporting the approach

outlined in the NPR in which EPA

would treat areas that had previously

received NOX waivers under section

182(f) of the CAA in the same manner

as other areas in the SIP call. The

comments stated that (1) special

treatment (i.e., higher budget) for the

waiver areas would increase the burden

on downwind States; (2) numerous

modeling efforts, including OTAG’s,

have shown that such disbenefits are

generally minor and occur on days with

low ozone concentrations; (3)

disbenefits are small when upwind NOX

reductions are modeled; (4) disbenefits

are better addressed at the local level;

and (5) States already have the

flexibility to deal with NOX disbenefits,

if any, through the budget and trading

by meeting the budget through NOX

emission decreases in other areas of the

State or acquiring allowances through

trading. In addition, some commenters

requested EPA to revoke waivers

previously granted. Commenters also

noted that the localized disbenefits are

no less of a problem in the Northeast

than in the Midwest.

Numerous comments were also

submitted which oppose the approach

outlined in the NPR. The comments

generally stated that in States with NOX

waiver areas, the NOX budget should be

increased where NOX decreases lead to

ozone increases; otherwise States might

seek reductions disproportionately

outside the sensitive areas, resulting in

cost-effectiveness levels greater than the

$2000 per ton framework described in

the SIP call proposals. Comments

referred to disbenefits in Cincinnati,

Louisville and the Chicago/Gary areas.

Many commenters suggested that EPA

wait for further modeling analyses to be

completed and that the zero-out runs are

inappropriate for evaluating the NOX

disbenefit issue. Some stated that the

NOX budget might interfere with local

attainment and harm local public

health. Other comments recommended

that EPA consider the impact of

additional VOC costs that might be

needed to offset local ozone increases.

Response: In today’s final rulemaking,

EPA is setting NOX emissions budgets

for each of the jurisdictions affected by

this action. These budgets are set in the

same manner for areas without NOX

waivers as areas with NOX waivers,

except in the case of NOX waivers

granted for I/M programs. Although
Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations 57425

adverse comments were submitted,

none of them provided any modeling

analysis or support documentation

showing how a State or States with NOX

waiver areas should be assigned a larger

budget or proposing a specific

alternative approach for assigning those

budgets. In contrast, modeling described

by EPA in the NPR and SNPR as well

as additional modeling conducted by

the Agency and some commenters

continues to show that the benefits of

NOX emissions decreases greatly

outweigh any disbenefits. These

findings are discussed in Section IV,

and summarized below.

The EPA considered the strengths and

limitations in the commenters’

modeling analyses in evaluating

whether the technical evidence

presented in the comments supports the

arguments made by the commenters.

The EPA’s review of the commenters’

modeling indicates that in general (a)

downwind ozone benefits increase as

greater NOX controls are applied to

sources in upwind States, (b) the net

benefits of NOX control at the level of

the SIP Call outweigh any local

disbenefits, and (c) upwind NOX

reductions tend to mitigate local

disbenefits in downwind areas.

One commenter, the Lake Michigan

Air Director’s Consortium (LADCO),

submitted air quality modeling directed

toward investigating the disbenefits in

nonattainment areas around Lake

Michigan due to the NOX controls in the

SIP Call proposal. The commenter’s

general finding was that the greatest

ozone decreases with these NOX

controls occur on high ozone days,

while the greatest disbenefits occur on

low ozone days. The EPA concurs with

this finding, based on a review of the

technical information provided by the

commenter. Specifically, there were no

predicted increases in ozone (i.e.,

disbenefits) in peak 1-hour ozone on

any of the 4 days modeled by LADCO

that had daily maximum 1-hour

concentrations >=125 ppb in the Base

Case. Also, on the 3 low ozone days

which had predicted disbenefits, the

increases were not large enough to

result in a peak value >=125 ppb.

Concerning 8-hour concentrations, only

1 of the 9 days with a predicted 8-hour

daily maximum concentration >=85 ppb

had an increase in peak ozone due to

the SIP Call NOX controls. Also, there

was a small disbenefit on the one day

modeled which had an 8-hour daily

maximum concentration <85 ppb, but

the magnitude of the disbenefit on this

day was relatively small and did not

cause the 8-hour peak value to exceed

85 ppb. Thus, based on this evaluation,

EPA generally found that the submitted

modeling did not refute the overall

conclusions EPA has drawn concerning

the impacts of NOX emissions in the

relevant geographic areas.

As described in the NPR, the OTAG

process included lengthy discussions on

the potential increase in local ozone

concentrations in some urban areas that

might be associated with a decrease in

local NOX emissions. The OTAG

modeling results indicate that urban

NOX emissions decreases produce

increases in ozone concentrations

locally, but the magnitude, time, and

location of these increases generally do

not cause or contribute to high ozone

concentrations. That is, NOX reductions

can produce localized, transient

increases in ozone (mostly due to lowlevel, urban NOX reductions) in some

areas on some days, but most increases

occur on days and in areas where ozone

is low. In the SNPR, EPA documented

the estimated ozone benefits of the

proposed Statewide NOX budgets based

on an air quality modeling analysis. The

major findings of that analysis include:

Any disbenefits due to the NOX

reductions associated with the budgets

are expected to be very limited

compared to the extent of the air quality

benefits expected from these budgets.

The results of EPA’s assessment of the

comments and available modeling

corroborate and extend the findings

presented in the SNPR. Thus, with

respect to regional ozone transport and

today’s final action, EPA believes it is

not appropriate to give special treatment

to areas with NOX waivers.

Several nonattainment areas in the 23

jurisdictions were granted waivers from

certain NOX requirements in past

rulemaking actions. In the Federal

Register notices granting the waivers,

EPA stated that the continued approval

of these waivers is contingent on the

results of the final ozone attainment

demonstrations and plans (See 61 FR

2428 January 26, 1996, LADCO). The

attainment plans will supersede the

initial modeling information which was

the basis for waivers EPA granted (e.g.,

the LADCO waiver). The attainment

plans were due in April 1998 and were

to incorporate the results of the OTAG

process. The EPA’s rulemaking action to

reconsider the initial NOX waiver may

occur simultaneously with rulemaking

action on the attainment plans.

Therefore, as these new modeling

analyses are submitted to EPA, they will

be reviewed to determine if the NOX

waiver should be continued, altered, or

removed.

As discussed above, EPA has

accounted for the continued presence of

NOX waivers for I/M programs in

modeling States’ NOX budgets.

Historically, EPA gives States

considerable latitude in designing their

I/M programs. This latitude is granted in

recognition of the unique economic and

air quality circumstances faced by each

State. States have used this latitude to

develop a range of I/M program designs.

Some States have adopted EPArecommended enhanced I/M programs;

other States have adopted different I/M

program designs.

The EPA acknowledges that some of

the States granted NOX waivers may be

able to modify their programs to obtain

NOX reductions at minimal cost.

However, some of the States which have

been granted an I/M NOX waiver have

developed unique I/M program designs

in terms of the model years covered, the

emission testing equipment used, and

possibly the number, location, and

design of the testing and repair stations.

The cost for these States to modify their

I/M programs to obtain NOX reductions

are likely to exceed the level that EPA

has determined to be highly costeffective for the purpose of reducing

ozone transport. As a result, the EPA

has chosen to not include additional

emissions reductions due to I/M NOX

programs when calculating NOX

budgets.

5. Recalculation of Budgets

In the NPR, the EPA made proposals

concerning what would happen if

additional information becomes

available after EPA’s final rulemaking

action. Examples of such information

might include: (a) Source-specific

information useful in determining

RACT, (b) revised growth or other

assumptions, (c) revised models and

inventory estimates, (d) unexpectedly

low implementation rates for NLEV, and

(e) other new federal measures, i.e. Tier

2 controls. In the Recalculation of

Budgets Section of the NPR, EPA

proposed that if additional data become

available after EPA’s final rulemaking

action, such data could be considered

prior to State submittal of revised SIPs.

The EPA asked for comments on this

approach.

Most of the comments received were

in favor of allowing States to adjust their

emission budgets based on the most

recent available data on emissions and

RACT levels. There were several

comments that any new calculation

methodologies should be applied across

all States and be approved at EPA

Headquarters, and that all States should

use the same methodology.

A few commenters did not agree,

however. One said that EPA should not

recalculate the budgets upward.

Another said there should be no

downward ratcheting of budgets. One
57426 Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations

commenter said that it would be

premature to assume that as new

information becomes available the

budget should be adjusted to reflect this.

According to this commenter, it would

be more appropriate to perform a

complete air quality modeling analysis

to determine if an adjustment in States’

NOX budgets is in order.

The divergent views reflected in these

comments has convinced EPA that it

should clarify the role of the budgets in

this rule. In light of that role, as

explained below, EPA has decided to

allow only a limited opportunity to

revise the budgets in the very near term.

However, under the approach the

Agency is following, the rule would not

penalize States for not ultimately

achieving the budgets, if the State

initially projected compliance using the

data set forth in this rule, and the State

has fully implemented all of the

measures reflected in those initial

projections, and the measures are as

effective in reducing NOX emissions as

they were projected to be in the State

plan.

As explained in the NPR, SNPR, and

above, EPA based the budgets on its

choice of measures that are highly costeffective and therefore are the easiest for

upwind States to implement to reduce

transport. However, EPA sought to

structure the rule to give the upwind

States a choice of which mix of

measures to adopt to achieve the

aggregate amount of required NOX

emissions reduction.

To offer the States this choice, EPA

employed a multi-step approach leading

to a numerical budget for each State. In

the first step, EPA projected the mass

emissions for EGUs and industrial

boilers out to 2007, taking into account

measures required under the CAA and

projected growth. The result was a base

case 2007 subinventory for each of those

two categories. Next, EPA projected the

2007 mass emissions for other sectors of

the emission inventory (e.g., mobile

sources), again taking into account

projected growth and measures required

under the CAA and existing SIPs,

thereby creating a base case 2007

subinventory for each of them as well.

The aggregation of all of the base case

2007 subinventories is the complete

base case 2007 inventory. The EPA then

applied cost-effective control measures

to the EGU, industrial boiler and other

non-EGU source categories as explained

in section III., to determine the amount

of the reductions from these categories.

The EPA applied control measures to

the base case inventory to develop the

final budget. Thus, the final budget is

the sum of (1) the emissions remaining

after application of the cost-effective

control measures to the subinventories

for the categories for which controls are

assumed for purposes of budget

calculation and (2) the emissions in the

base case 2007 subinventories for the

categories for which EPA assumed no

controls.

The rule then requires each upwind

State to use the same base case 2007

inventory in its 1999 SIP submittal as

EPA used in developing the State’s

budget. In that SIP submittal, the State

must show that the measures it has

adopted will achieve the same aggregate

emissions reductions as the control

strategies assumed by EPA in

developing the State’s budget. More

specifically, to demonstrate compliance

with the SIP call, a State must adopt and

implement control measures that are

projected to achieve the aggregate

emissions reductions determined by

EPA based on the application of highly

cost-effective controls to EGUs,

industrial boilers and other affected

non-EGUs. While a State may choose to

achieve those reductions through

application of measures other than those

used by EPA in calculating required

reductions, any measures it adopts must

achieve the reductions assumed by EPA

in the development of its budgets.

The control measures that the State

chooses to require will become the

enforceable mechanism under the NOX

SIP call. If a State elects to regulate

boilers, turbines or combined cycle

units that are greater than 250 mmBtu/

hr— regardless of whether they are

connected to an electrical generator of

any size—or to regulate boilers, turbines

and combined cycle units that serve

electrical generators greater than 25

Mwe, regardless of the heat input

capacity of the unit, the State must

provide mass emissions limits or their

equivalent (see section VI.A.2) for these

sources or source categories. The mass

emissions limits may be set on a sourceby-source basis or may be set for an

entire group of sources allowing trading

between the sources. These mass

emission limits must assume growth no

greater than EPA’s calculations. Any

growth that occurs in that category

would have to be accommodated within

the mass emission allocations provided

by the State for that category, even if the

growth in that category should prove to

exceed EPA’s projections. This is

appropriate because as discussed in the

SNPR and Section VI.A.2. of today’s

preamble, EPA believes that the control

approaches, growth assumptions, and

monitoring for this group of sources

have advanced to the point that

complying with, tracking, and enforcing

a maximum mass emissions limit is

reasonable. Furthermore, based on the

analyses in the RIA, EPA believes that

mass emission limits remain highly

cost-effective for these categories when

growth is accommodated within the

limits. The EPA modeled the expected

growth in capacity and capacity

utilization of the source categories listed

above based on growth assumptions in

the IPM that have been subject to

extensive public comment and

refinement over a several-year period.

On the basis of their growth,

assumptions and assumed emissions

rates, EPA determined that mass

emission limits would remain highly

cost-effective when new sources are

covered within the limits. EPA projects

that even if actual growth for this group

of sources exceeds the projected growth

by over one-third, mass emission limits

would remain highly cost-effective

according to the criteria used for this

rule.

For other categories, EPA will not

require a State to remain within a mass

emission allocation. Today’s rule does

require a State to use the base case 2007

inventory in its budget demonstration.

However, the rule does not require

States to obtain additional reductions in

cases where a State’s 2007 emissions

exceeds its budget due to higher than

expected emissions from source

categories other than the categories

listed above (certain boilers, turbines,

and combined cycle units). These

exceedances may be the result of growth

that exceeds projections for those source

categories. However, if a State elects to

control these other source categories to

achieve the required reductions in

whole or part, the adopted measures

must be as effective in reducing NOX

emissions as they were projected to be

in the State plan. Any failure by a State

to adopt measures adequate to achieve

reductions equal to the required amount

would be treated as noncompliance

with this rule. Any failure by the State

to implement these measures by the

appropriate date would be considered a

failure to implement those measures.

In contrast, the overall budget number

itself is not enforceable against the

State. The budget serves as a tool for

projecting in advance whether a State

has adopted measures that would

produce the required amount of

emissions reductions, as indicated by

the initial demonstration submitted in

September 1999. The budgets are also a

means for determining from 2003 to

2007 whether States are fully

implementing those measures. Thus, the

budgets are an accounting mechanism

for ensuring that the upwind States have

adopted and implemented control

measures that prohibit the significant
Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations 57427

amounts of NOX emissions targeted by

section 110(a)(2)(D)(i)(I).

Given that States will not be subject

to enforcement actions if emissions in

2007 from uncontrolled sectors exceed

the base case 2007 inventory

projections, EPA does not intend to

revise those projections merely because

such new information becomes

available over time. Rather, EPA intends

to allow commenters an additional

opportunity to request revisions to the

source-specific data used to establish

each State’s budget in this SIP call. This

opportunity will be made available

during the first sixty days of the 12-

month period between signature of

today’s rule and the deadline for

submission of the required SIP revisions

(i.e., November 23, 1998). Commenters

would need to submit any proposed

changes in their inventories to the EPA

Air and Radiation docket (A–96–56)

within that sixty day period. Individuals

interested in modifications requested by

commenters may review the materials as

they are submitted and available in the

docket. At the end of this period, EPA

will, within sixty days, evaluate the data

submitted by commenters and, if it is

determined to be technically justified,

revise this rule to incorporate it into the

State budget determinations. For a

comment to be considered, the request

for modification must be submitted in

electronic format containing, at a

minimum, the data elements listed

below for each source category.

Additionally, no comment will be

considered unless information is

provided to corroborate and justify the

need for the requested modification. For

example, corroborating information in

the case of the EGUs can be the

inclusion of copies of each source’s

official same year EIA 860 or 861 form

submissions that support the requested

change. For non-EGUs, corroborating

information can include 1995

operational and emissions information

officially submitted (during that time

period) by the source to a federal, State,

or local government regulating entity.

Each request for modification of data

for EGU sources must include the

following information:

• Federal Information Placement

System State Code.

• Federal Information Placement

System (FIPS) County Code.

• Plant name.

• Plant ID numbers (ORIS code

preferred, State agency tracking number

also or otherwise).

• Unit ID numbers (a unit is a boiler

or other combustion device).

• Unit type (also known as prime

mover; e.g., wall-fired boiler, stoker

boiler, combined cycle, combustion

turbine, etc.).

• Primary fuel on a heat input basis.

• Maximum rated heat input capacity

of unit.

• For electrical generating units,

nameplate capacity of the largest

generator the unit serves.

• For 1995 and 1996 ozone season

heat inputs.

• 1996 (or most recent) average NOX

rate for the ozone season.

• Latitude and longitude coordinates.

• Stack parameter information

(height, diameter, flow, etc.).

• Operating parameters (hours per

day, seasonal throughput, etc.).

• Identification of specific change to

the inventory, and

• The reason for the change.

Each request for modification of data

for non-EGU point sources must include

the following information:

• Federal Information Placement

System State Code.

• Federal Information Placement

System (FIPS) County Code.

• Plant name.

• Facility primary standard industrial

classification code (SIC).

• Plant ID numbers (NEDS, AIRS/

AFS, and State agency tracking number

also or otherwise).

• Unit ID numbers (a unit is a boiler

or other combustion device).

• Primary source classification code

(SCC).

• Maximum rated heat input capacity

of unit.

• 1995 ozone season or typical ozone

season daily NOX emissions.

• 1995 existing NOX control

efficiency.

• Latitude and longitude coordinates.

• Stack parameter information

(height, diameter, flow, etc.).

• Operating parameters (hours per

day, seasonal throughput, etc.).

• Identification of specific change to

the inventory, and

• The reason for the change.

Each request for modification of data

for stationary area and nonroad mobile

sources must include the following

information:

• Federal Information Placement

System State Code.

• Federal Information Placement

System (FIPS) County Code.

• Primary source classification code

(SCC).

• 1995 ozone season or typical ozone

season daily NOX emissions.

• 1995 existing NOX control

efficiency.

• Identification of specific change to

the inventory, and

• The reason for the change.

Each request for modification of data

for highway mobile sources must

include the following information:

• Federal Information Placement

System State Code.

• Federal Information Placement

System (FIPS) County Code.

• Primary source classification code

(SCC) or vehicle type.

• 1995 ozone season or typical ozone

season daily vehicle miles traveled

(VMT).

• 1995 existing NOX control

programs.

• Identification of specific change to

the inventory, and

• The reason for the change.

After this initial ‘‘shake out’’ period

before submission of the SIP revisions,

EPA will not adjust inventories or the

resulting State budgets merely because

some new information on a segment of

EPA’s projections comes to its attention.

However, when EPA reviews each

State’s reports, it will pay special

attention to the causes for any

exceedance of the portions of the

inventory that the State is controlling as

a means to meet today’s rule. If a State

exceeds its budget because of greaterthan-expected growth in areas not

having additional controls, EPA would

not penalize the State by requiring the

State to offset those increased

emissions. Rather, EPA would use the

base case projections for all sectors (as

revised after the initial period described

above) and focus on whether the State

had implemented the measures that its

1999 demonstration had shown would,

based on those base case inventories,

achieve the budget levels. Similarly, the

rule would not penalize the State if

components in the budget prove

inaccurate because of changes in models

(e.g., the release of an updated MOBILE

model) or because of technical errors

(e.g., the size of a unit was incorrectly

identified in the inventory, a unit was

double-counted, or the RACT level

assumed in the base is different from

what the State ultimately selected as

RACT with EPA approval).

In the NPR, EPA also raised the

question of what would happen if EPA

adopts national measures beyond what

EPA already assumed in the base case

2007 inventory. The EPA indicated that

it could use either of two approaches in

response: (1) States could receive credits

for the real emission reductions that

result from the new Federal measures

and, therefore, implement a smaller

portion of its planned emission

reductions, or (2) States would be

required to continue to implement the

measures in their revised SIPs because

affected States are required to continue

to achieve emissions reductions

equivalent to those which can be

achieved through application of highly

cost-effective control measures.
57428 Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations

One commenter supported the

emission reduction credit for State SIPs

resulting from new Federal national

measures adopted after the State

emission budgets are defined but before

2007. According to this commenter, in

such a case the State could implement

a smaller portion of its planned

emission reductions because of the

reduction brought about by the Federal

national rule. Another commenter said

the EPA should allow full credit for all

Federal measures and encouraged the

EPA to timely implement and adopt all

Federal measures. A State said States

should be allowed to take full SIP credit

for Federal measures which are

implemented in these States. According

to one commenter, not allowing States

to take credit for new Federal measures

would have the effect of downward

ratcheting of NOX budgets. Other States

said new Federal measures not

accounted for in the SIP call should not

be used to offset State measures

required to achieve the mandated NOX

emissions reductions.

The EPA has decided to adopt the

second approach described above. Thus,

EPA’s adoption of a national measure

not reflected in the base case 2007

inventory would not allow the State to

avoid a measure that would otherwise

be needed to demonstrate that the State

will achieve the required reductions. As

stated above, the SIP must prohibit all

emissions that contribute significantly

to downwind nonattainment and

maintenance problems. The State

therefore is required to eliminate an

amount of emissions corresponding to

what is achievable with the highly costeffective measures identified in this

notice. The comments received have not

provided an adequate basis for

concluding that EPA’s adoption of an

additional national measure justifies

scaling back on that requirement. For

that reason, EPA will not allow States to

adjust the base case 2007 inventory

inventories to reflect any such

additional national measures. Rather,

for these reports the States should

continue to use the base case 2007

inventory set forth in this rule.

In the SNPR, EPA also discussed

establishing a process for reassessing the

State budgets for the post-2007

timeframe. Today’s final rule is based

on analyses using the most complete,

scientifically-credible tools and data

available for the assessment of transport.

The EPA expects that there will be a

number of updates and refinements in

air quality methodologies and emissions

estimation techniques over the next 10

years. Therefore, EPA intends to

reassess ozone transport using the latest

emissions and air quality monitoring

data and the next generation of air

quality modeling tools. The

reassessment will include an evaluation

of the effectiveness of the regional NOX

measures States have implemented in

response to today’s final rule. Modeling

analyses will be used to evaluate

whether additional local or regional

controls are needed to address residual

nonattainment in the post-2007

timeframe. The assessment will also

examine differences in actual growth

versus projected growth in the years up

to 2007 as well as expected future

growth throughout the entire OTAG

region. The reassessment will also

review advances in control technologies

to determine what reasonable and costeffective measures are available for

purposes of controlling local and

regional ozone problems. In addition,

EPA will continue to look at the issues

that surround the use of output-based

State budget allocations. Based on this

reassessment, EPA may establish new

budget levels and allocation

mechanisms for the post-2007

timeframe. The current budget levels

and the measures used to comply with

today’s final rule will remain in effect

until EPA takes action on establishing

new State budgets.

6. Compliance Supplement Pool

The EPA has received comments

expressing concern that some sources

may encounter unexpected problems

installing controls by the compliance

deadline that, in turn, could cause

unacceptable risks for a source and its

associated industry. More specifically,

commenters have expressed concerns

related to the electricity industry. If

unexpected problems arise for specific

sources that are used to generate

electricity, some commenters believe

that compliance with the May 1, 2003

deadline could adversely impact the

reliability of the electricity supply.

Commenters that raised concerns

regarding the compliance deadline

generally supported additional

compliance flexibility for the SIP call.

In both the NPR and SNPR, EPA

solicited comment on a number of

provisions that would provide

additional flexibility to both States and

sources for the requirements of the NOX

SIP call. In the NPR, EPA proposed that

the NOX SIP call would require full

implementation of controls by no later

than September 2002, but solicited

comment on the range of

implementation dates from between

September 2002 and September 2004. In

addition to the compliance deadline,

EPA also solicited comment on the role

of banking as a separate compliance

flexibility for the NOX SIP call. Banking

may generally be defined as allowing

sources that make emissions reductions

beyond current requirements to save

and use these excess reductions to

exceed requirements in a later time

period. Depending upon the design of a

trading program, banking provisions can

provide companies greater latitude for

when controls are installed at particular

sources. In the SNPR, EPA presented a

range of options for incorporating

banking in the NOX Budget Trading

Program including early reduction

provisions and phasing in controls. The

EPA received many comments

supporting banking in the NOX Budget

Trading Program and also as a general

flexibility mechanism that should be

permissible for any State program used

to comply with the NOX SIP call.

In response to comments supporting

an extended compliance deadline, EPA

has moved the deadline from the

proposed date of September 2002 in the

NPR to May 1, 2003. As discussed

further in Section V, this change

provides sources 7–8 additional months

for implementing control requirements

while ensuring that controls are fully

implemented by the 2003 ozone season.

The EPA believes that the compliance

date of May 1, 2003 for NOX controls to

be installed to comply with the NOX SIP

call is a feasible and reasonable

deadline. See Section V.A.1. and the

technical support document ‘‘Feasibility

of Installing NOX Control Technologies

By May 2003’’ for further discussion.

To provide additional flexibility to

States and sources for complying with

the NOX SIP call beyond the extension

of the compliance deadline, EPA is

establishing banking provisions and a

compliance supplement pool in today’s

final rule. The banking provisions are

outlined in Section III.F.7. The

compliance supplement pool is a

voluntary provision that provides

flexibility to States in addressing

concerns associated with full

compliance by May 1, 2003. Each State

will be able to use the pool to cover

excess emissions of sources that are

unable to meet the compliance deadline

during the 2003 and 2004 ozone

seasons. The pool may be used to credit

sources that make early reductions and

to directly delay the compliance

deadline for specific sources. Credits

issued from the compliance supplement

pool will not be valid for compliance

past the 2004 ozone season. The EPA

established the compliance supplement

pool by calculating one pool for the

entire NOX SIP call region. The pool

was then allocated to the States in

proportion to the size of the emissions

reduction they are required to achieve

under the NOX SIP call so that each
Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations 57429

State has its own compliance

supplement pool. The size of each

State’s compliance supplement pool and

the procedures that will apply to the use

of the pool are described below.

a. Size of the Compliance Supplement

Pool. The EPA believes it is important

for the size of the pool to be capped.

Capping the pool makes it possible to

estimate the potential impact that the

compliance supplement pool may have

on NOX emissions during the 2003 and

2004 ozone seasons. Furthermore, EPA

does not anticipate problems for sources

in meeting the May 1, 2003 deadline. If

there are such cases, they should be

relatively few in number. Therefore, the

size of the pool only needs to be large

enough to cover the limited potential for

unexpected compliance delays.

Today’s final rule sets the size of the

regional compliance supplement pool at

200,000 tons. The EPA believes this is

a reasonable size for the pool given the

analyses that were used in establishing

the State NOX budgets for today’s final

rule. As discussed in Section V.A.1.,

EPA believes the most cost-effective

control strategies available to comply

with the proposed budgets include postcombustion controls (Selective Catalytic

Reduction [SCR] and Selective Noncatalytic Reduction [SNCR]) and

combustion controls (e.g., low NOX

burners, overfire air, etc.) on large

electric generating units and large nonelectric generating units. For the reasons

cited in Section V.A.1., EPA estimates

that the implementation of SCR controls

is potentially more complicated and

requires more time than SNCR or

combustion controls and, therefore,

would determine what the longest

schedule would be for full

implementation of the assumed NOX

controls. Since EPA estimates that a

single SCR installation will take about

23 months, EPA expects the first SCR

installations to be completed in 2001.

Since compliance is required by 2003,

one can assume 33 percent of SCR

capacity will be installed each year from

2001 to 2003. The 200,000 ton number

is sufficient to cover the excess

emissions that must be offset if one

year’s worth of SCR installations were

delayed by a year. Table III–3 shows

each State’s compliance supplement

pool. The 200,000 tons were allocated to

States in proportion to the size of the

emissions reduction they are required to

achieve under the NOX SIP call. The

EPA used this allocation methodology

based on the assumption that the need

for the pool would be directly related to

the magnitude of the emissions

reductions required in each State to

comply with the NOX SIP call.

TABLE III–3.—STATE COMPLIANCE SUPPLEMENT POOLS

[Tons]

State Base Budget Tonnage

reduction

Compliance

supplement

pool

Alabama ............................................................................................................ 218,610 158,677 59,933 10,361

Connecticut ....................................................................................................... 43,807 40,573 3,234 559

Delaware ........................................................................................................... 20,936 18,523 2,413 417

District of Columbia .......................................................................................... 6,603 6,792 (189) 0

Georgia ............................................................................................................. 240,540 177,381 63,159 10,919

Illinois ................................................................................................................ 311,174 210,210 100,964 17,455

Indiana .............................................................................................................. 316,753 202,584 114,169 19,738

Kentucky ........................................................................................................... 230,997 155,698 75,298 13,018

Maryland ........................................................................................................... 92,570 71,388 21,182 3,662

Massachusetts .................................................................................................. 79,815 78,168 1,648 285

Michigan ........................................................................................................... 301,042 212,199 88,842 15,359

Missouri ............................................................................................................ 175,089 114,532 60,557 10,469

New Jersey ....................................................................................................... 106,995 97,034 9,960 1,722

New York .......................................................................................................... 190,358 179,769 10,590 1,831

North Carolina .................................................................................................. 213,296 151,847 61,450 10,624

Ohio .................................................................................................................. 372,626 239,898 132,728 22,947

Pennsylvania .................................................................................................... 331,785 252,447 79,338 13,716

Rhode Island .................................................................................................... 8,295 8,313 (18) 0

South Carolina .................................................................................................. 138,706 109,425 29,281 5,062

Tennessee ........................................................................................................ 252,426 182,476 69,950 12,093

Virginia .............................................................................................................. 191,050 155,718 35,332 6,108

West Virginia .................................................................................................... 190,887 92,920 97,967 16,937

Wisconsin ......................................................................................................... 145,391 106,540 38,851 6,717

Total ........................................................................................................... 4,179,751 3,023,113 ........................ 200,000

b. State Distribution of the

Compliance Supplement Pool. States

have two options for making the pool

available to sources. One option is to

distribute some or all of the pool to

sources that generate early reductions

during ozone seasons prior to May 1,

2003. The second option is to run a

public process to provide tons to

sources that demonstrate a need for a

compliance extension. A State wishing

to use the compliance supplement pool

may divide the State pool and make

some of it available to sources through

both options, or may use only one of the

options for distributing the pool to

sources prior to May 1, 2003 according

to the procedures discussed below. Tons

that are not distributed by a State prior

to May 1, 2003 will be retired by EPA.

(1) Early Reduction Credits. The EPA

encourages States to consider making

the compliance supplement pool

available to sources through an early

reduction credit program. States may

use early reduction credits as an

incentive for sources to make NOX

emissions reductions prior to the 2003

ozone season that would otherwise not

occur. By generating early credits or

acquiring them from other sources,

companies will be able to use the early

reduction credits to extend the

timeframe for achieving actual

emissions reductions at specific sources

that may require additional time. To

establish an early credit program, States

that participate in the NOX Budget

Trading Program may use the provisions
57430 Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations

set forth in that trading program (See

Section VII.F). States not participating

in the NOX Budget Trading Program are

also free to develop their own rules for

granting early reduction credits and

recognizing the credits for compliance

during the 2003 and 2004 ozone

seasons. The procedures for establishing

an early credit program are presented

below in Section III.F.7.c.

(2) Direct Distribution to Sources.

States may also distribute the

compliance supplement pool directly to

sources that demonstrate a need for the

compliance supplement. Under this

approach, sources would be responsible

for demonstrating to the State and

public that achieving compliance by

May 1, 2003 would create undue risk

either to its own operation or its

associated industry. Before granting a

direct distribution to a source, the State

must provide the public an opportunity

to comment on the validity of the need

for direct distribution of the compliance

supplement. The direct distribution

process must be initiated and completed

between September 30, 2002 and May 1,

2003. States which choose to grant early

reduction credits cannot conduct the

direct distribution until all early

reduction credits have been issued by

the State. By postponing the direct

distribution until after September 2002,

sources will have the maximum

opportunity to achieve compliance,

either through installation of controls or

with early reduction credits, before

using this option. States and the public

will also be better positioned to

determine legitimate requests after

September 2002.

To ensure that direct distribution of

the compliance supplement is only

provided to sources that truly need a

compliance extension, States are only

permitted to give credits to an owner or

operator of a source that demonstrates

the following:

• The process of achieving

compliance by May 1, 2003 would

create undue risk for the source or its

associated industry. For electric

generating units, the demonstration

should show that installing controls

would create unacceptable risks for the

reliability of the electricity supply

during the time of installation. This

demonstration would include a showing

that it was not feasible to import

electricity from other systems during the

time of installation. Non-electric

generating sources may also be eligible

for the compliance supplement based on

a demonstration of risk comparable to

that described for the electricity

industry.

• For a source subject to an early

reduction credit program, it was not

possible to compensate for delayed

compliance by generating early

reduction credits at the source or by

acquiring credits generated by other

sources.

• For a source subject to an emissions

trading program, it was not possible to

acquire allowances or credits for the

2003 ozone season from sources that

will make reductions beyond required

levels during the 2003 ozone season.

7. Banking

As noted in the NPR and SNPR, States

have the flexibility to choose their own

set of control measures to meet their

Statewide NOX budget established

under the NOX SIP call. States and

sources have supported the use of

emissions trading programs as a control

measure for complying with the NOX

SIP call requirements. EPA has provided

a model cap-and-trade program (NOX

Budget Trading Program) for large

stationary sources that States can adopt

as one option for establishing an

emissions trading program. A number of

commenters (both States and sources)

have also expressed interest in pursuing

alternative trading programs in addition

to or as a substitute for the NOX Budget

Trading Program. One possible

flexibility mechanism available to

sources subject to an emissions trading

program is the ability to bank emissions

reductions. Banking may generally be

defined as allowing sources that make

emissions reductions beyond required

levels to save and use these excess

reductions to compensate for emitting

emissions above required levels in a

later time period. In the SNPR, EPA

requested comment on whether and

how banking should be incorporated

into the design of the NOX Budget

Trading Program. In the proposal, four

banking options were presented: (1)

Banking would not be a feature; (2)

banking would begin when the trading

program begins (May 2003); (3) sources

would be allowed to generate early

reductions credits for use after the start

of the program and banking would

continue after the program begins; (4)

banking would begin with the first

phase of a two-phase trading program

and continue thereafter (i.e., phased-in

control requirements). The EPA also

requested comment on options for

managing the use of banked allowances

in order to limit the potential for

emissions to be significantly higher than

budgeted levels because of banking. The

EPA specifically proposed using a ‘‘flow

control’’ mechanism in the latter two

banking options where the potential

exists for a large amount of banked

allowances to be available for use at the

start of the program.

a. Banking Starting in 2003.

Comments for the NOX Budget Trading

Program were generally supportive of

including banking in the trading

program. Commenters noted that

allowing sources to make excess

reductions in one year and use these

reductions to emit above required levels

in a later year encourages early and costsaving emission reductions, helps avoid

end-of-season emissions spikes (because

unused allowances retain their value for

compliance in future years), and

encourages more expedient

development and implementation of

NOX control technology. Commenters

pointed out that banking also provides

sources flexibility in achieving emission

reduction goals, allowing them to save

allowances in years when the cost of

achieving a given emission level is

relatively low for use in years when the

cost is relatively higher (for example, a

year characterized by low availability of

nuclear and hydro generation capacity

would be a higher cost year). Thus,

banking was seen by many commenters

as a critical tool for sources to respond

to uncertainty. Some commenters,

however, expressed caveats along with

their support for banking. They cited the

need for some form of bank management

to ensure that the use of banked

allowances does not detract from the

environmental goal of the NOX SIP call.

At least one commenter recommended

that EPA identify banking as an area to

be reviewed for problems during audits

of the program to ensure it did not have

a detrimental impact.

The EPA also received comments

supporting banking that were not

specific to the NOX Budget Trading

Program. Many commenters addressed

the concept of banking when proposing

alternative strategies for establishing

and implementing the State budgets that

were proposed in the NOX SIP call.

These comments regarded banking as a

fundamental factor in establishing the

timing and control level for the State

budgets. With all other factors being

equal, a NOX SIP call that allows

banking provides additional flexibility

and cost savings to affected sources than

a NOX SIP call without banking. For this

reason, many commenters included

banking in their alternative proposals.

In order to provide additional

flexibility to States and sources under

the NOX SIP call as discussed in section

III.F.6., and recognizing that States may

pursue alternative trading programs

other than the NOX Budget Trading

Program, the Agency believes it is

important to establish criteria for

banking that would apply to all

programs that States may use to comply

with requirements of the NOX SIP call.
Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations 57431

Therefore, EPA is setting forth

provisions in today’s final rule that will

allow banking in the NOX Budget

Trading Program and other State trading

programs. Trading programs used to

comply with the NOX SIP call may

allow banking to start in the first control

period of the program, May 1 through

September 30, 2003. Beginning in that

control period, States may allow sources

included in these programs to bank NOX

emissions reductions not otherwise

required by the State’s SIP, for

compliance in future control periods. As

outlined below, the banking provisions

also require the use of a flow control

mechanism beginning in 2004 and allow

States to credit early reductions

generated by sources prior to 2003 that

may be used for compliance only in the

2003 and 2004 ozone seasons. The final

rule for the NOX Budget Trading

Program conforms with these banking

provisions. Additionally, alternative

emissions trading programs used to

comply with the SIP call will be subject

to these banking criteria as well other

applicable criteria in § 51.121 and any

other applicable EPA guidance such as

the Economic Incentive Program rules

and guidance.

b. Management of Banked

Allowances. Many utility and industry

commenters generally opposed the use

of discounts or constraints on banked

allowances, arguing that such measures

would reduce the incentives to control

emissions beyond required levels. In

addition, commenters felt the measures

were overly complex and restrictive, as

well as unnecessary, since the stringent

control level proposed would serve as a

barrier to overcontrol, precluding the

establishment of a sizeable bank.

Several commenters remarked that any

decision regarding whether and to what

extent a trading program should impose

restrictions on the use of banked

allowances should proceed from an

analysis of the air quality effects of that

use; in the absence of such an analysis,

there would be little basis for imposing

restrictions or for deciding what

restrictions would properly address air

quality effects. However, these

commenters did not provide analyses

demonstrating that the use of banked

allowances in any given season would

not be a problem in the context of the

NOX SIP call. One commenter pointed

out specifically that the sheer

magnitude of the SIP call region should

preclude EPA from implementing a flow

control management scheme similar to

that used under the Ozone Transport

Commission’s (OTC) trading program,

since protection of problem areas would

not be feasible on such a large scale.

Several commenters who were

opposed to the management of banked

allowances, however, stated that if

restrictions were to be imposed, they

would favor flow control as the most

cost-effective, least rigid means of

management. A few commenters added

that, if implemented, flow control

should be applied on a source-by-source

basis so as to avoid penalizing all of the

participants in the trading program for

the excess banking of individual

participants. One commenter stated that

if EPA concludes that there is an

adequate basis for imposing some type

of restriction, it should avoid placing

any absolute limit on the amount of

banked allowances that can be used in

a given season. Another commenter

suggested that if EPA chooses to

propose managed banking, it should

consider establishing an initial period

without managed banking upon which a

managed banking program can later be

based if it turns out that ‘‘trading

contributes to nonattainment.’’ Several

additional commenters, most notably

northeastern States and a few

environmental groups, supported the

use of a flow control management

system to discourage excess use of

banked allowances in any one ozone

season. One such commenter suggested

that EPA conduct an analysis similar to

that used by the OTC in determining the

appropriate level of flow control for the

SIP call region.

Based on the stated goal of the NOX

SIP call, to achieve specified limits on

NOX emissions for the purpose of

reducing NOX and ozone transport

across State boundaries in the eastern

half of the United States, EPA believes

it is appropriate to place some

limitation on the amount of emissions

variability that may occur with banking,

and therefore, occur with the transport

of NOX. At the same time, any

limitations on banking should still fit

within the market-based structure of

trading programs, rather than imposing

overly stringent limits that would

potentially eliminate the advantages of

having banking in the first place. For

these reasons, EPA is including a

provision in today’s final rule requiring

any State program used to comply with

the requirements of the NOX SIP call

that allows banking to limit the

potential effects of banking through a

flow control mechanism as described

below. The flow control mechanism will

be applicable starting in the 2004 ozone

season. In this year, unused credits from

the compliance supplement pool as well

as unused credits or allowances from

the 2003 ozone season would be

considered banked.

The EPA believes that the flow

control mechanism serves as an

important insurance policy against

emissions variability in emissions

trading programs used to comply with

the NOX SIP call. The mechanism as

described below would only restrict the

use of banked allowances or credits

when a significant amount are used for

compliance in a specific ozone season.

Based on the analyses in the RIA, EPA

believes that the flow control

mechanism is set at a level that will

allow sources to use banking without

restriction. However, the flow control

mechanism provides the extra security

to downwind areas that banking will not

result in significant increases of

emissions above budgeted levels. The

EPA also recognizes that a wide variety

of emissions trading programs may be

used by States. Therefore, the

requirements for the flow control

mechanism described below are

intended to be general, thus allowing

States the flexibility to adjust the flow

control mechanism to fit the specific

needs of each program. Section VII.F.

also provides further discussion of the

flow control mechanism and describes

how it is incorporated into the NOX

Budget Trading Program.

The flow control mechanism allows

the unlimited banking of emissions

reductions by sources during and after

2003, but discourages the ‘‘excessive

use’’ of banked allowances or credits by

establishing either an absolute limit on

the number of banked allowances or

credits that can be used each season or

a rate discounting the use of banked

allowances or credits over a given level.

The key issue with flow control is to

establish the level at which flow control

is triggered. In the SNPR, EPA solicited

comment on establishing the level at 10

percent of the ozone season budget for

the sources included in the trading

program. This level was proposed

because 10 percent seems to be a

reasonable number that would allow a

significant amount of banked

allowances or credits to be used, but not

so many as to jeopardize the intended

effects of the NOX SIP call in a given

season. The EPA also proposed the 10

percent number because it is the level

used for flow control in the OTC’s

trading program. Although some

commenters questioned whether this

number is appropriate for the NOX SIP

call region, commenters did not provide

explicit analyses or recommendations

for a different number. Thus, EPA

continues to believe that 10 percent is

a reasonable number and is including

this in today’s final rule. Based on the

analyses in the RIA, EPA does not
57432 Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations

anticipate sources to bank above the 10

percent level. Therefore, this level

should prevent significant emissions

increases resulting from banking

without restricting sources normal

operations. The effect of flow control set

at 10 percent of the trading program

budget is that for a given season, sources

may use banked allowances or credits

for compliance without restrictions in

an amount up to 10 percent of the NOX

budget for those sources in the trading

program. Banked allowances or credits

that are used in an amount greater than

10 percent of the NOX budget for those

sources will have restrictions that are

described below.

The EPA believes it is necessary to

provide flexibility to States for

determining how to apply the 10

percent flow control in individual

trading programs and for determining

the appropriate restrictions for banked

allowances or credits that are used in an

amount greater than the 10 percent

number. States have the flexibility to

apply the flow control mechanism to

specifically control the use of banked

allowances or credits at each source or

to apply the mechanism more broadly

across the entire trading program. For

example, by applying flow control at the

source level, a State would allow each

source participating in the trading

program to use banked allowances

without restrictions in an amount not

greater than 10 percent of its allowable

NOX emissions for the ozone season.

Conversely, flow control could be

applied so that individual sources may

use banked allowances or credits in an

amount more than 10 percent without

restrictions, but the total number used

throughout the entire trading program

(i.e., total number of banked credits or

allowances used for compliance

throughout all States participating in the

trading program) could not exceed 10

percent of the allowable NOX emissions

for all sources in the trading program

without restrictions. The net effect is the

same under either approach—banked

allowances or credits may be used each

year without restrictions in an amount

that does not exceed 10 percent of the

allowable NOX emissions for all sources

covered by the trading program. The

NOX Budget Trading Program uses the

latter approach. See Section VII.F. for

more details.

The second issue for the flow control

mechanism is to determine what

restrictions should be placed on banked

allowances or credits that are used in an

amount greater than 10 percent of the

allowable NOX emissions for all sources

covered by the trading program. Again,

EPA is providing flexibility for the

restrictions that States may use. States

may use a discount that is no less than

two-for-one, requiring sources to retire

one additional banked allowance or

credit for each banked allowance or

credit used for compliance in an amount

greater than the 10 percent level. Or

States may set the 10 percent level as a

hard cap and not allow any banked

allowances or credits to be used in an

amount greater than the 10 percent

level. Although the discount option

provides more flexibility to sources and

more uncertainty regarding NOX

emissions in a given year, EPA believes

both options serve as an acceptable

restriction for limiting the variability of

emissions associated with banking. As

described in Section VII.F, the NOX

Budget Trading Program uses the 2-for1 discount as the applicable restriction.

c. Early Reduction Credits. The

majority of commenters for the NOX

Budget Trading Program generally

supported the option of awarding early

reduction credits. Commenters noted

that the issuance of credits will provide

cost savings and environmental benefits

by encouraging early reductions,

facilitate compliance with the budget by

allowing sources to earn allowances that

may be used to delay more stringent

emission reductions, and stimulate the

market by ensuring allowances are

available for trading at the program

start. Several commenters advocated

making early reduction credits available

for any reductions that exceed baseline

controls, whereas other commenters

supported early reduction credits only if

they exceed the controls required under

the SIP call, as was proposed by EPA.

A few other commenters suggested

levels between these two options. A few

OTC States suggested that OTC

allowances banked in Phase II (between

1999–2003 for reductions beyond an

approximate 0.20 lb/mmBtu rate) could

be used as early reduction credits in the

NOX Budget Trading Program, either

one-for-one or at a discount ratio,

depending on the level beyond which

credits were awarded in the latter

program. A few remaining commenters,

concerned about the potential for

creating or exacerbating ozone

violations, supported early reduction

credits and banking only if coupled

with flow control.

Regarding the appropriate length of

the period in which early reductions

could be earned, some commenters

supported EPA’s proposed option in the

SNPR of a two-year early reduction

period, while others favored a three or

four-year period. At least one

commenter specifically recommended

that the early reduction period start in

January 1995, while another suggested

September 1998. Several commenters

rejected EPA’s suggestion that early

reduction credits be calculated as a setaside from the first five years of

allowances, arguing that treating the

credits as set-asides would be

inconsistent with the nature of early

reduction credits. Conversely, a few

other commenters felt the credits should

be awarded from within State budgets to

avoid budget inflation. Additional

commenters criticized EPA’s suggestion

that if early reduction credits were

awarded, they be awarded at the

company level, arguing instead for

individual source awards. One

commenter stated that awards on a

company basis would not address the

load shifting concerns EPA cited, while

another thought EPA could address the

load shifting concern by basing credits

on activity levels in a historic period

rather than by shifting to a companylevel award. Finally, at least one

commenter felt that States should be

able to independently establish

parameters for awarding voluntary early

reductions.

For the reasons set forth in Section

III.F.7, Compliance Supplement Pool,

EPA is allowing, but not requiring,

States to grant early reduction credit to

sources that reduce their ozone season

NOX emissions below levels specified

by the State prior to the 2003 control

period. The early reduction credits may

be used by sources for compliance

during the 2003 and 2004 ozone

seasons. EPA believes that an early

credit program can be helpful to

encourage emissions reductions prior to

the 2003 ozone season that would not be

made without an economic incentive for

the sources to act. Furthermore, the

early credit program will provide

additional allowances or credits for use

during the 2003 and 2004 ozone

seasons. By generating early credits or

acquiring early credits from other

sources that generated credits,

companies would have greater latitude

in determining when actual emissions

reductions are achieved at specific

sources. As discussed in Section III.F.7,

this may be beneficial to some

companies that are concerned about the

time and effort required to install all

necessary emissions controls prior to

May 2003. States will be limited in the

amount of early reduction credits that

they may grant by the amounts set forth

in Section III.F.7 Compliance

Supplement Pool. The potential pool of

credits that is available to each State is

intended to be large enough to provide

a real incentive for early reductions and

enough flexibility to allow the

installation of some control equipment,

if necessary, past May 2003.
Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations 57433

Section VII.F. of today’s preamble

outlines how the early credit program is

being incorporated into the NOX Budget

Trading Program and how banked

allowances from the OTC program may

be integrated with this provision. States

that develop alternative trading

programs may craft their early reduction

program to meet the needs of their

specific trading program. The following

outlines the general requirements that

any early reduction program used to

comply with the NOX SIP call should

meet. For an emission reduction to be

eligible as an early reduction credit, it

must meet the following criteria:

• Surplus—The reduction is not

contained in the State’s SIP or otherwise

required by the CAA.

• Verifiable—The reduction can be

verified as actually having occured.

• Quantifiable—The reduction is

quantified according to procedures set

forth by the State and approved by EPA.

Early reduction credits generated by

sources serving electric generators with

a nameplate capacity greater than 25

MWe or greater or boilers, combustion

turbines and combined cycle units with

a maximum design heat input greater

than 250 mmBtu/hr, should be

quantified according to the monitoring

provisions of part 75, subpart H as

required in § 51.121(h)(1)(iv).

Beyond the above requirements,

States are free to develop an early credit

program that meets the needs of their

specific trading program provided the

State does not issue credits in an

amount greater the size of the credit

pool presented in Section III.F.7. A

State’s early credit program may be

established for any ozone season

occurring after a State’s early credit rule

is approved by EPA into the State’s SIP

revision and before May 1, 2003.

To ensure that a State does not issue

an amount of early credits beyond the

amount specified in each State’s

compliance supplement pool, EPA

recommends that a State develop

procedures to be used in case there is an

over-subscription of the early credit

pool. Possible options include granting

early credits on a first-come, first-served

basis or waiting until all applications

are submitted and then discounting the

early credits on a pro-rata basis so that

the amount of early credits issued

equals the size of the State’s pool. States

may also influence the amount of early

credits that sources generate by

considering what level of emissions

reductions the State will recognize as

early reductions. For example, a State

may choose to issue early reduction

credits for any reductions below

applicable requirements. However, the

State may choose to make the

demonstration more stringent by

requiring early reduction credits to be

generated by reductions that are below

a limit that is tighter than applicable

requirements (e.g., grant early

reductions that are 30 percent below

applicable requirements or below a

fixed level such as 0.20 lb/mmBtu).

In the SNPR, EPA also solicited

comment on a phased-in NOX Budget

Trading Program that would begin in

2001, two years prior to the compliance

date for the NOX SIP call. In response

to the proposal, most commenters that

discussed the phase-in program option

were generally opposed to it. Their

primary argument was that such a

program would effectively accelerate the

compliance date for NOX controls under

the SIP call. A few commenters,

however, still supported the phase-in

approach as a means of mitigating the

uncertainties inherent in the allowance

market that would develop for the 2003

control period, allowing sources to gain

experience prior to 2003. Some

commenters specifically favored a

phase-in approach only if it does not

interfere with the 2003 ozone season

compliance schedule, whereas others

supported a phase-in approach as a

means of reducing the burdens of the

2003 ozone season compliance

schedule.

Today’s final rule requires States to

achieve the necessary emissions

reductions by May 2003 and does not

require States to phase-in controls prior

to 2003. States that wish to phase-in

controls prior to 2003 as a part of a State

trading program may do this, but they

are not required to do so to comply with

the NOX SIP call. States that establish a

phased-in trading program in order to

allow sources to generate early

reduction credits will be subject to the

requirements for early reductions as

described above, including the

requirement that a State may not grant

an amount of early reductions in excess

of the State’s compliance supplement

pool. For a discussion of how the Ozone

Transport Commission’s trading

program may be integrated with the

compliance supplement pool and the

early reduction provisions, see Section

VII.F, which describes the banking

provisions of the NOX Budget Trading

Program.

G. Final Statewide Budgets

1. EGU

a. Description of Selected Approach.

As described in Section III.B.3. of this

notice, the EGU budget component is

calculated based on applying a 0.15 lb/

mmBtu emission limit to sources greater

than 25 MWe. This limit is applied

uniformly across all States that are

covered by this SIP call. The higher of

1995 or 1996 heat input, grown to 2007

is used to calculate the budget

component.

b. Summary of Budget Component.

Both the 2007 electricity generating

Base Case and the electricity generating

Budget component were revised from

the levels in the SNPR based on the

changes described in Section III.B.3. of

this notice. These revisions are shown

in Tables III–4 and III–5. The difference

between the revised 2007 Base Case and

Budget emissions from the SNPR and

the final Base Case and Budget

emissions is shown in Table III–4.

Negative changes indicate decreases.

The final percent reduction from the

2007 Base Case to the Budget is shown

in Table III–5.

TABLE III–4.—CHANGES TO REVISED SNPR BASE CASE AND BUDGET COMPONENTS FOR ELECTRICITY GENERATING

UNITS

[Tons NOX/season]

State Revised base Final base Percent

change

Revised

budget Final budget Percentchange

Alabama .................................................................... 85,201 76,900 –10 30,644 29,051 –5

Connecticut ............................................................... 7,048 5,600 –21 5,245 2,583 –51

Delaware ................................................................... 10,727 5,800 –46 4,994 3,523 –29

District of Columbia ................................................... 236 *0 –100 152 207 36

Georgia ..................................................................... 84,890 86,500 2 32,433 30,255 –7

Illinois ........................................................................ 119,756 119,300 0 36,570 32,045 –12

Indiana ...................................................................... 159,917 136,800 –14 51,818 49,020 –5

Kentucky ................................................................... 130,919 107,800 –18 38,775 36,753 –5
57434 Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations

TABLE III–4.—CHANGES TO REVISED SNPR BASE CASE AND BUDGET COMPONENTS FOR ELECTRICITY GENERATING

UNITS—Continued

[Tons NOX/season]

State Revised base Final base Percent

change

Revised

budget Final budget Percentchange

Maryland ................................................................... 37,575 32,600 –13 12,971 14,807 14

Massachusetts .......................................................... 24,998 16,500 –34 14,651 15,033 3

Michigan .................................................................... 73,585 86,600 18 29,458 28,165 –4

Missouri ..................................................................... 81,799 82,100 0 26,450 23,923 –10

New Jersey ............................................................... 17,484 18,400 5 8,191 10,863 33

New York .................................................................. 43,705 39,200 –10 31,222 30,273 –3

North Carolina ........................................................... 86,872 84,800 –2 32,691 31,394 –4

Ohio ........................................................................... 167,601 163,100 –3 51,493 48,468 –6

Pennsylvania ............................................................. 120,979 123,100 2 45,971 52,000 13

Rhode Island ............................................................. 1,351 1,100 –19 1,609 1,118 –31

South Carolina .......................................................... 57,146 36,300 –36 19,842 16,290 –18

Tennessee ................................................................ 83,844 70,900 –15 26,225 25,386 –3

Virginia ...................................................................... 51,113 40,900 –20 20,990 18,258 –13

West Virginia ............................................................. 76,374 115,500 51 24,045 26,439 10

Wisconsin .................................................................. 45,538 52,000 14 17,345 17,972 4

Total ................................................................... 1,568,655 1,501,800 –4 563,784 543,825 –4

*The base case for DC is actually projected to be 3 tons per season. The base case values in this table are rounded to the nearest 100 tons.

TABLE III–5.—FINAL NOX BUDGET COMPONENTS AND PERCENT REDUCTION FOR ELECTRICITY GENERATING UNITS

[tons/season]

State Final base Final budget Percent reduction

Alabama ....................................................................................................................................... 76,900 29,051 62

Connecticut ................................................................................................................................... 5,600 2,583 54

Delaware ...................................................................................................................................... 5,800 3,523 39

District of Columbia ...................................................................................................................... *0 207 NA

Georgia ......................................................................................................................................... 86,500 30,255 65

Illinois ............................................................................................................................................ 119,300 32,045 73

Indiana .......................................................................................................................................... 136,800 49,020 64

Kentucky ....................................................................................................................................... 107,800 36,753 66

Maryland ....................................................................................................................................... 32,600 14,807 55

Massachusetts .............................................................................................................................. 16,500 15,033 9

Michigan ....................................................................................................................................... 86,600 28,165 67

Missouri ........................................................................................................................................ 82,100 23,923 71

New Jersey ................................................................................................................................... 18,400 10,863 41

New York ...................................................................................................................................... 39,200 30,273 23

North Carolina .............................................................................................................................. 84,800 31,394 63

Ohio .............................................................................................................................................. 163,100 48,468 70

Pennsylvania ................................................................................................................................ 123,100 52,000 58

Rhode Island ................................................................................................................................ 1,100 1,118 –2

South Carolina .............................................................................................................................. 36,300 16,290 55

Tennessee .................................................................................................................................... 70,900 25,386 64

Virginia .......................................................................................................................................... 40,900 18,258 55

West Virginia ................................................................................................................................ 115,500 26,439 77

Wisconsin ..................................................................................................................................... 52,000 17,972 65

Total ...................................................................................................................................... 1,501,800 543,825 64

*The base case for DC is actually projected to be 3 tons per season. The base case values in this table are rounded to the nearest 100 tons.

2. Non-EGU Point Sources

As indicated in the proposal and

discussed earlier in this notice, EPA

continues to believe that technically

feasible control measures costing

between an average of $1,000 to $2,000

per ozone season ton (1990 dollars) are

highly cost-effective and therefore

should be the basis for determining the

significant amounts that must be

eliminated by each covered jurisdiction.

In the SNPR, EPA committed to

examining alternatives that would limit

the number of affected non-EGU sources

for the purpose of establishing

emissions budgets, yet still achieve the

environmental objective of mitigating

broad-scale ozone transport. The EPA

examined alternatives that target

reductions from the largest non-EGU

source category groupings, and within

each of the largest groupings applied the

cost-effectiveness criteria. The resulting

emissions budget covers the majority of

emissions from large non-utility

sources, and does not include

reductions from small sources and

sources that, as a group, are not efficient

to control, or are already covered by

other Federal measures (e.g., CAA § 112

MACT). The description below

summarizes the budget approach for

non-EGU point sources.

a. Description of Selected Approach.

(1) NOX Budget Sources. The

following approach is used to determine

if a unit’s emissions would be decreased

as part of the budget calculation.
Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations 57435

Industrial boilers, turbines, stationary

internal combustion engines and cement

manufacturing are the only non-EGU

sources for which reductions are

assumed in the budget calculation.

1. Use heat input capacity data for

each source if the data are in the

updated inventory.

2. If heat input capacity data are not

available, use the default identification

of small and large sources developed by

EPA/Pechan for OTAG and also used to

develop the NPR and SNPR budgets for

source categories with heat input

capacity fields (‘‘default data’’).

3. Emission reductions would be

assumed if specific source heat input

capacity data or default data indicate

that a source is greater than 250 mmBtu/

hr in the updated inventory.

4. If specific or default heat input

capacity data are not available in the

updated inventory (or not appropriate

for a particular source category),

emission reductions would be assumed

if the unit’s average summer day

emissions are greater than one ton per

day based on the updated inventory.

5. All others are ‘‘small’’ and no

emission reductions are assumed.

It should be noted (as described

earlier in this section) that no emissions

reductions are assumed for point

sources with capacities less than or

equal to 250 mmBtu/hr but with

emissions greater than 1 ton/day for

purposes of calculating the budget. This

is a change from the NPR which

assumed RACT controls on units with

capacities less than or equal to 250

mmBtu/hr and emissions greater than 1

ton/day.

(2) Control Levels. For purposes of

calculating the State NOX budgets for

the relevant sources (described above),

the following emissions decreases from

uncontrolled levels were assumed:

1. Non-EGU boilers and turbines—

60% decrease.

2. Stationary internal combustion

engines—90% decrease.

3. Cement manufacturing plants—

30% decrease.

These controls result in an overall

reduction in emissions from all affected

large non-EGU point sources of almost

40 percent (187,800 tons per season

decrease).

Each State’s budget is based on

application of these controls beginning

on May 1, 2003. The EPA recognizes

that if States include these source

categories in a regionwide trading

program, as EPA encourages States to

do, each State will comply with its

budget through compliance of its

sources with the requirements of the

regionwide trading program. Of course,

under the trading program, sources in a

State may acquire or sell allowances

that will, in turn, allow for higher or

lower emissions levels for that State

than assumed in this action. Because

EPA has determined that the ambient

effect of such a trading program across

the region is consistent with the basis

for including States in the SIP call (see

discussion below at Section IV), EPA

has structured its rule to allow a State

to meet its budget by including the

amount of emissions for which sources

in the State hold allowances from outof-State sources. Overall, total NOX

emissions in the region will be within

the budget.

b. Summary of Budget Component.

Both the 2007 Base Case and Budget

component for non-electricity

generating point sources were revised

based on the changes described above.

Changes to the 2007 base reflect changes

in the base year (1995) emissions and

changes in growth factors. Changes to

the budget components reflect these

changes as well as the change in level

of control. These resulting budget

components are shown in Tables III–5

and III–6. The difference between the

2007 Base Case and Budget emissions as

revised in the SNPR and the final Base

Case and Budget emissions for nonelectricity generating point sources is

shown in Table III–6. Negative changes

indicate decreases. The final percent

reduction from the 2007 Base Case to

the Budget is shown in Table III–7.

TABLE III–6.—CHANGES TO REVISED BASE CASE AND BUDGET COMPONENTS FOR NON-ELECTRICITY GENERATING POINT

SOURCES

[Tons NOX/season]

Revised base Final base Percent

change

Revised budget Final budget Percent

change

Alabama .................................................... 48,187 49,781 3 24,416 37,696 54

Connecticut ............................................... 5,254 5,273 0 3,103 5,056 3

Delaware ................................................... 5,276 1,781 ¥66 2,271 1,645 ¥28

District of Columbia ................................... 311 310 0 259 292 13

Georgia ..................................................... 33,939 33,939 0 14,305 27,026 89

Illinois ........................................................ 65,351 55,721 ¥15 40,719 42,011 3

Indiana ...................................................... 51,839 71,270 37 29,187 44,881 54

Kentucky ................................................... 19,019 18,956 0 11,996 14,705 23

Maryland ................................................... 10,710 10,982 3 5,852 7,593 30

Massachusetts .......................................... 9,978 9,943 0 6,207 9,763 57

Michigan .................................................... 61,656 79,034 28 35,957 48,627 35

Missouri ..................................................... 12,320 13,433 9 9,012 11,054 23

New Jersey ............................................... 22,228 22,228 0 12,786 19,804 55

New York .................................................. 20,853 25,791 24 14,644 24,128 65

North Carolina ........................................... 34,412 34,027 ¥1 19,267 25,984 35

Ohio ........................................................... 53,329 53,241 0 30,923 35,145 14

Pennsylvania ............................................. 74,839 73,748 ¥1 41,824 65,510 57

Rhode Island ............................................. 327 327 0 327 327 0

South Carolina .......................................... 34,994 34,740 ¥1 18,671 25,469 36

Tennessee ................................................ 67,774 60,004 ¥11 34,308 35,568 4

Virginia ...................................................... 25,509 39,765 56 10,919 27,076 148

West Virginia ............................................. 42,733 40,192 ¥6 21,066 31,286 49

Wisconsin .................................................. 21,263 22,796 7 11,401 17,973 58

Total ................................................... 722,101 757,281 5 399,416 558,618 40
57436 Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations

TABLE III–7.—FINAL NOX BUDGET COMPONENTS AND PERCENT REDUCTION FOR NON-ELECTRICITY GENERATING POINT

SOURCES

[Tons/season]

Final base Final budget Percent

reduction

Alabama ....................................................................................................................................... 49,781 37,696 24

Connecticut ................................................................................................................................... 5,273 5,056 4

Delaware ...................................................................................................................................... 1,781 1,645 8

District of Columbia ...................................................................................................................... 310 292 6

Georgia ......................................................................................................................................... 33,939 27,026 20

Illinois ............................................................................................................................................ 55,721 42,011 25

Indiana .......................................................................................................................................... 71,270 44,881 37

Kentucky ....................................................................................................................................... 18,956 14,705 22

Maryland ....................................................................................................................................... 10,982 7,593 31

Massachusetts .............................................................................................................................. 9,943 9,763 2

Michigan ....................................................................................................................................... 79,034 48,627 38

Missouri ........................................................................................................................................ 13,433 11,054 18

New Jersey ................................................................................................................................... 22,228 19,804 11

New York ...................................................................................................................................... 25,791 24,128 6

North Carolina .............................................................................................................................. 34,027 25,984 24

Ohio .............................................................................................................................................. 53,241 35,145 34

Pennsylvania ................................................................................................................................ 73,748 65,510 11

Rhode Island ................................................................................................................................ 327 327 0

South Carolina .............................................................................................................................. 34,740 25,469 27

Tennessee .................................................................................................................................... 60,004 35,568 41

Virginia .......................................................................................................................................... 39,765 27,076 32

West Virginia ................................................................................................................................ 40,192 31,286 22

Wisconsin ..................................................................................................................................... 22,796 17,973 21

Total ...................................................................................................................................... 757,281 558,618 26

3. Mobile and Area Sources

a. Description of Selected Budget

Approach. As discussed in Section

III.D.3 of the notice, EPA proposed

highway budget components based on

projected highway vehicle emissions in

2007 from a base year of 1990, assuming

implementation of those measures

incorporated in existing SIPs, such as

inspection and maintenance programs

and reformulated fuels, measures

already implemented federally, and

those additional measures expected to

be implemented federally by 2007. As

discussed in Section III.E of this notice,

EPA proposed nonroad mobile source

budget components based on projected

nonroad mobile source emissions in

2007 from a base year of 1990. These

projections were developed by

estimating the emissions expected in

2007 from all nonroad engines,

assuming implementation of those

measures incorporated in existing SIPs,

measures already implemented

federally, and those additional measures

expected to be implemented federally.

For area sources, no cost-effective

control measures were identified in the

NPR. Because no comments were

received that demonstrate that

additional controls for highway,

nonroad, or area sources are both

feasible and highly cost-effective, the

final budgets are based on the same

levels of controls that were proposed.

b. Summary of Budget Component.

Changes were made to the baseline

stationary area, nonroad and highway

mobile source budget data as discussed

in Sections III.D. and III.E. of this notice.

Budget components were calculated

using the updated baseline and the

controls discussed above. The resulting

final budget components for these

sectors are contained in Tables III–7, III–

8, and III–9 below, along with the

difference between the proposed Budget

emissions and the final Budget

emissions. The budget components are

not compared to the 2007 base because

no reductions were calculated beyond

the base case. In the NPR and SNPR,

EPA used a 2007 CAA baseline for these

source sectors. Because the measures

that are assumed in the budgets for

these sectors are measures that would

occur in the absence of the SIP call, EPA

believes that it is more appropriate to

use the budget level for these source

sectors as the baseline and compare the

total budgets to this revised baseline.

TABLE III–8.—FINAL NOX BUDGET COMPONENTS FOR STATIONARY AREA SOURCES

[Tons/season]

Proposed

budget Final budget Percentchange

Alabama ....................................................................................................................................... 25,229 25,225 0

Connecticut ................................................................................................................................... 4,587 4,588 0

Delaware ...................................................................................................................................... 1,035 963 ¥7

District of Columbia ...................................................................................................................... 741 741 0

Georgia ......................................................................................................................................... 11,901 11,902 0

Illinois ............................................................................................................................................ 7,270 7,822 8

Indiana .......................................................................................................................................... 25,545 25,544 0

Kentucky ....................................................................................................................................... 38,801 38,773 0

Maryland ....................................................................................................................................... 8,123 4,105 ¥49

Massachusetts .............................................................................................................................. 10,297 10,090 ¥2
Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations 57437

TABLE III–8.—FINAL NOX BUDGET COMPONENTS FOR STATIONARY AREA SOURCES—Continued

[Tons/season]

Proposed

budget Final budget Percentchange

Michigan ....................................................................................................................................... 28,126 28,128 0

Missouri ........................................................................................................................................ 6,626 6,603 0

New Jersey ................................................................................................................................... 11,388 11,098 ¥3

New York ...................................................................................................................................... 15,585 15,587 0

North Carolina .............................................................................................................................. 9,193 10,651 16

Ohio .............................................................................................................................................. 19,446 19,425 0

Pennsylvania ................................................................................................................................ 17,103 17,103 0

Rhode Island ................................................................................................................................ 420 420 0

South Carolina .............................................................................................................................. 8,420 8,359 ¥1

Tennessee .................................................................................................................................... 11,991 11,990 0

Virginia .......................................................................................................................................... 25,261 18,622 ¥26

West Virginia ................................................................................................................................ 4,901 4,790 ¥2

Wisconsin ..................................................................................................................................... 10,361 8,160 ¥21

Total ...................................................................................................................................... 302,350 290,689 ¥4

TABLE III–9.—FINAL NOX BUDGET COMPONENTS AND PERCENT REDUCTION FOR NONROAD SOURCES

[Tons/season]

Proposed

budget Final budget Percentchange

Alabama ....................................................................................................................................... 18,727 16,594 ¥11

Connecticut ................................................................................................................................... 9,581 9,584 0

Delaware ...................................................................................................................................... 4,262 4,261 0

District of Columbia ...................................................................................................................... 3,582 3,470 ¥3

Georgia ......................................................................................................................................... 22,714 21,588 ¥5

Illinois ............................................................................................................................................ 56,429 47,035 ¥17

Indiana .......................................................................................................................................... 27,112 22,445 ¥17

Kentucky ....................................................................................................................................... 22,530 19,627 ¥13

Maryland ....................................................................................................................................... 18,062 17,249 ¥4

Massachusetts .............................................................................................................................. 19,305 18,911 ¥2

Michigan ....................................................................................................................................... 24,245 23,495 ¥3

Missouri ........................................................................................................................................ 19,102 17,723 ¥7

New Jersey ................................................................................................................................... 21,723 21,163 ¥3

New York ...................................................................................................................................... 30,018 29,260 ¥3

North Carolina .............................................................................................................................. 18,898 17,799 ¥6

Ohio .............................................................................................................................................. 42,032 37,781 ¥10

Pennsylvania ................................................................................................................................ 29,176 25,554 ¥12

Rhode Island ................................................................................................................................ 2,074 2,073 0

South Carolina .............................................................................................................................. 12,831 11,903 ¥7

Tennessee .................................................................................................................................... 47,065 44,567 ¥5

Virginia .......................................................................................................................................... 25,357 21,551 ¥15

West Virginia ................................................................................................................................ 10,048 10,220 2

Wisconsin ..................................................................................................................................... 15,145 12,965 ¥14

Total ...................................................................................................................................... 500,018 456,818 ¥9

TABLE III–10. FINAL NOX BUDGET COMPONENTS AND PERCENT REDUCTION FOR HIGHWAY VEHICLES

[Tons/season]

Proposed

budget Final budget Percentchange

Alabama ....................................................................................................................................... 56,601 50,111 ¥11

Connecticut ................................................................................................................................... 17,392 18,762 8

Delaware ...................................................................................................................................... 8,449 8,131 ¥4

District of Columbia ...................................................................................................................... 2,267 2,082 ¥8

Georgia ......................................................................................................................................... 77,660 86,611 12

Illinois ............................................................................................................................................ 77,690 81,297 5

Indiana .......................................................................................................................................... 66,684 60,694 ¥9

Kentucky ....................................................................................................................................... 46,258 45,841 ¥1

Maryland ....................................................................................................................................... 28,620 27,634 ¥3

Massachusetts .............................................................................................................................. 23,116 24,371 5

Michigan ....................................................................................................................................... 81,453 83,784 3

Missouri ........................................................................................................................................ 55,056 55,230 0

New Jersey ................................................................................................................................... 39,376 34,106 ¥13

New York ...................................................................................................................................... 94,068 80,521 ¥14
57438 Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations

TABLE III–10. FINAL NOX BUDGET COMPONENTS AND PERCENT REDUCTION FOR HIGHWAY VEHICLES—Continued

[Tons/season]

Proposed

budget Final budget Percentchange

North Carolina .............................................................................................................................. 73,056 66,019 ¥10

Ohio .............................................................................................................................................. 92,549 99,079 7

Pennsylvania ................................................................................................................................ 73,176 92,280 26

Rhode Island ................................................................................................................................ 5,701 4,375 ¥23

South Carolina .............................................................................................................................. 49,503 47,404 ¥4

Tennessee .................................................................................................................................... 67,662 64,965 ¥4

Virginia .......................................................................................................................................... 79,848 70,212 ¥12

West Virginia ................................................................................................................................ 21,641 20,185 ¥7

Wisconsin ..................................................................................................................................... 41,651 49,470 19

Total ...................................................................................................................................... 1,179,477 1,173,163 ¥1

4. Potential Alternatives to Meeting the

Budget

The EPA believes that there are

additional control measures and

alternative mixes of controls that a State

could choose to implement by May 1,

2003. Examples of such measures are

described below and illustrate that

options are potentially available in

several source categories.

The EPA believes that, with respect to

EGUs, there is a large potential for

energy efficiency and renewables in the

NOX SIP call region that reduce demand

and provide for more environmentallyfriendly energy resources. For example,

if a company replaces a turbine with a

more efficient one, the unit supplying

the turbine would reduce the amount of

fuel (heat input) the unit combusts and

would reduce NOX emissions

proportionately, while the associated

generator would produce the same

amount of electricity. Renewable energy

source generation includes

hydroelectric, solar, wind, and

geothermal generation. EPA recognizes

that promotion of energy efficiency and

renewables can contribute to a costeffective NOX reduction strategy. As

such, EPA encourages States in the NOX

SIP call region to consider including

energy efficiency and renewables as a

strategy in meeting their NOX budgets.

One way to achieve this goal is by

including a provision within a State’s

NOX Budget Trading Rule that allocates

a portion of a State’s trading program

budget to implementers of energy

efficiency and renewables projects that

reduce energy-related NOX emissions

during the ozone season. Another is to

include energy efficiency and

renewables projects as part of a State’s

implementation plan.

The EPA is working to develop

guidance on how States can integrate

energy efficiency into their SIPs by both

of these mechanisms. The guidance will

present EPA’s current thinking on the

important elements to include in a

functional system that allocates a

portion of a State’s trading program

budget to implementers of energy

efficiency and renewables projects

within the context of the NOX Budget

Trading Program. In addition, EPA will

issue guidance outlining procedures for

including energy efficiency and

renewables projects in a State’s SIP as

control strategies for achieving the

State’s NOX budget, separate from the

NOX Budget Trading Program. EPA

plans to issue these guidance

documents in the Fall of 1998 so that

they will be available to States early in

their SIP planning process.

With respect to non-EGUs, individual

States could choose to require emissions

decreases from sources or source

categories that EPA exempted from the

budget calculations. For example, there

are many large sources for which EPA

lacked enough information to determine

potential controls and emissions

reductions; States may have access to

such information and could choose to

apply cost-effective controls. In

addition, States could choose to regulate

one or more of the non-EGU stationary

sources or source categories which EPA

had exempted because emissions were

relatively low considering other source

categories in the 23 jurisdictions. In

individual States, emissions from such

sources could be a high percentage of

uncontrolled emissions and, thus, be

subject to efficient, cost-effective control

for that particular State. Further, States

may take other approaches to

developing their budgets, such as

cutoffs based on horsepower rather than

tons per day, since they might have

access to data that EPA did not have for

all 23 jurisdictions.

With respect to mobile sources, States

could implement other NOX control

measures in lieu of the controls

described earlier in this section. For

example, vehicle inspection and

maintenance programs can provide

significant NOX reductions from

highway vehicles. Additional NOX

reductions can be obtained by opting

into the reformulated gasoline program,

by implementing measures to reduce the

growth in VMT, and by implementing

programs to accelerate retirement of

older, higher-emitting highway vehicles

and nonroad equipment.

5. Statewide Budgets

The revised Statewide budgets that

reflect the changes to the base year

inventory and growth factors for all

sectors and the revised control levels for

the non-EGU point source sector

described above are shown in Table III–

11. For the 23 jurisdictions combined,

the budgets result in a 28 percent

reduction from the base case. In the NPR

and SNPR the percent reduction was 35

percent. The difference in the percent

reduction is due to several factors. First,

in the NPR and SNPR reductions from

certain highway and nonroad controls

were assumed to occur as a result of

measures implemented between

promulgation of this rule and 2007.

These measures include National Low

Emission Vehicle Standards, the 2004

Heavy-Duty Engine Standards, the

Federal Small Engine Standards, Phase

II, Federal Marine Engine Standards (for

diesel engines of greater than 50

horsepower), Federal Locomotive

Standards, and the Nonroad Diesel

Engine Standards. These controls were

reflected in the budget but were not

included in the base case. For the final

rule, EPA determined that these

measures should be included in the base

case, rather than the budgets, because

the measures would be implemented

even in the absence of this rulemaking.

Based on the emission levels that were

used in the SNPR, the effect of using

this approach to setting the base case is

to decrease the percent reduction from

35 percent to approximately 31 percent.
Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations 57439

The additional change in the percent

reduction (from 31 percent to 28

percent) is primarily due to EPA’s

decision not to assume controls for

several non-EGU source categories and

to change the level of control for those

non-EGU categories for which controls

are assumed. Although the overall

percent reduction went from 35 percent

to 28 percent, the difference between

the budget proposed in the SNPR and

the final budgets in today’s notice is less

than 3 percent.

TABLE III–11.—REVISED STATEWIDE NOX Budgets

[Tons/season]

State Base Budget Percent

reduction

Alabama ....................................................................................................................................... 218,610 158,677 27

Connecticut ................................................................................................................................... 43,807 40,57 37

Delaware ...................................................................................................................................... 20,936 18,523 12

District of Columbia ...................................................................................................................... 6,603 6,792 ¥3

Georgia ......................................................................................................................................... 240,540 177,381 26

Illinois ............................................................................................................................................ 311,174 210,210 32

Indiana .......................................................................................................................................... 316,753 202,584 36

Kentucky ....................................................................................................................................... 230,997 155,698 33

Maryland ....................................................................................................................................... 92,570 71,388 23

Massachusetts .............................................................................................................................. 79,815 78,168 2

Michigan ....................................................................................................................................... 301,042 212,199 30

Missouri ........................................................................................................................................ 75,089 114,532 35

New Jersey ................................................................................................................................... 106,995 97,034 9

New York ...................................................................................................................................... 190,358 179,769 6

North Carolina .............................................................................................................................. 213,296 151,847 29

Ohio .............................................................................................................................................. 372,626 239,898 36

Pennsylvania ................................................................................................................................ 331,785 252,447 24

Rhode Island ................................................................................................................................ 8,295 8,31 30

South Carolina .............................................................................................................................. 138,706 109,425 21

Tennessee .................................................................................................................................... 252,426 182,476 28

Virginia .......................................................................................................................................... 191,050 155,718 18

West Virginia ................................................................................................................................ 190,887 92,920 51

Wisconsin ..................................................................................................................................... 145,391 106,540 27

Total .............................................................................................................................................. 4,179,751 3,023,113 28

IV. Air Quality Assessment

A. Assessment of Proposed Statewide

Budgets

In the SNPR, EPA documented the

estimated ozone benefits of the

proposed Statewide NOX budgets based

on an air quality modeling analysis. The

major findings of that analysis are as

follows:

(1) The emissions reductions

associated with the proposed Statewide

budgets are predicted to produce large

reductions in both 1-hour and 8-hour

concentrations in areas which currently

violate the NAAQS and which would

likely continue to have violations in the

future without the SIP call budget

reductions.

(2) Looking at individual ozone

‘‘problem areas’’ considered by OTAG

shows similar results, based on the

available metrics.

(3) Any ‘‘disbenefits’’ due to the NOX

reductions associated with the budgets

are expected to be very limited

compared to the extent of the benefits

expected from these budgets.

(4) Even though the budgets are

expected to reduce 1-hour and 8-hour

ozone concentrations across all 23

jurisdictions, nonattainment problems

requiring additional local control

measures will likely continue in some

areas currently violating the NAAQS.

(63 FR 25903)

B. Comments and Responses

The EPA received numerous

comments on the air quality modeling of

the proposed NOX budgets. The

following is a summary of the main

comments and EPA’s responses.

Comment: Commenters stated that the

emissions inventories used for modeling

were flawed because EPA’s projection of

the base year emissions to 2007

improperly treated growth for certain

electric generation units by growing

these units beyond their design

capacity.

Response: The EPA agrees with this

comment and has revised the 2007

emissions projections for modeling to

take this factor into account. For the

modeling described in the SNPR, EPA

applied State-level growth factors

uniformly to existing sources in each

State. This did not account for

maximum capacity and could have

resulted in sources being modeled with

emissions that were higher than their

actual capacity would allow. For the

modeling described in this notice, EPA

has revised the projection procedures to

use IPM to allocate growth to existing

units considering their design capacity.

As described below, EPA has remodeled

the 2007 Base Case and the Statewide

budgets using this revised inventory and

found that the conclusions from the

revised runs do not differ from those

based on the SNPR model runs of these

budgets.

Comment: Commenters stated that

EPA’s modeling in the SNPR examined

the impacts of the budgets applied

regionwide (i.e., for each State for which

a budget is required), rather than the

impacts on downwind nonattainment of

the budgets applied only in upwind

States. Therefore, according to the

commenters, this modeling is not useful

for indicating the impact of the State

budgets on downwind nonattainment or

maintenance problems.

Response: The EPA is well aware that

many States in the SIP Call region are

both upwind and downwind States, that

is, they are upwind of certain

nonattainment areas and downwind

from other States. For example,

Pennsylvania is upwind of New York

City, and emissions from Pennsylvania

sources significantly contribute to this

nonattainment problem; and
57440 Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations

Pennsylvania is downwind of several

States, emissions from which

significantly contribute to

Philadelphia’s nonattainment problem.

The EPA is further aware that

modeling analyses that evaluate

emissions reductions in each State

affected by today’s rulemaking do not

isolate the precise impact of emissions

reductions from each upwind State on

nonattainment in a State that is itself

both an upwind and downwind State.

That is, the emissions reductions in that

upwind/downwind area impact its own

nonattainment problems. To return to

the example noted above, because

emissions reductions in Pennsylvania

affect Philadelphia’s air quality,

modeling Pennsylvania’s emissions

reductions along with emissions

reductions in all other affected States

does not isolate the impact of emissions

reductions from States upwind of

Pennsylvania on Philadelphia’s air

quality. As a result, EPA is aware that

the regionwide modeling of different

budget levels does not indicate the

differential impact on downwind areas

of higher budget levels as compared to

lower budget levels in upwind areas.

Nevertheless, EPA believes that

regionwide modeling of the State

budgets is a useful indication of the

overall impacts of various budget levels.

Today’s rulemaking requires regionwide

emissions reductions, which will carry

certain costs and will have certain

impacts viewed on a State-by-State basis

and on a regionwide basis. The multiState budgets promulgated today mean

that in a State that is both upwind and

downwind of other States, such as

Pennsylvania, the air quality will, in

fact, be improved by the emissions

reductions in upwind States and by the

reductions within the States that are

required to improve air quality further

downwind. Thus, it is necessary to

consider the upwind emissions

reductions together with the downwind

emissions reductions in order to fully

evaluate the air quality impacts of the

Statewide budgets. Regionwide

modeling is the only available approach

to indicate these ‘‘real world’’ impacts

in individual States, as well as allow an

assessment of those impacts in light of

their costs. Accordingly, this modeling

is useful in evaluating the overall

impacts of the alternative budget levels

considered in the course of the

rulemaking. The EPA believes that a

comparison of the overall impacts of

alternative budget levels, in turn, serves

as a means to confirm whether the

budget levels promulgated in today’s

rulemaking yield meaningful air quality

benefits. Moreover, EPA has conducted

other modeling which indicates the

impact of budget-level emissions on air

quality downwind, as discussed below.

Comment: Commenters stated that

EPA should have modeled the proposed

budgets on a State-by-State basis in

order to assess the downwind benefits

of applying the budgets in each State.

Response: The EPA performed a

multi-factor analysis to determine the

amount of a State’s emissions that

significantly contribute to downwind

nonattainment and what the resulting

State budget should be. This is

discussed in detail in Section II.C.,

Weight of Evidence Determination of

Covered States. Specifically, EPA

determined that emissions from all

sources in certain States contribute to

downwind problems, but that only a

portion of those emissions—in some

cases, a relatively small portion—may

be reduced through highly cost-effective

controls. The EPA established a budget

for each State based on the elimination

of these emissions. After EPA

established the budgets, EPA performed

air quality modeling to quantify the

overall ozone benefits of the budgets

applied in all upwind States on selected

downwind areas. This modeling is

described below. The EPA considered

the results of this modeling as an

additional piece of evidence in the

analysis to confirm that the amount of

emissions reductions from upwind

States collectively provide meaningful

reductions in nonattainment downwind.

For the purposes of this modeling it

is sufficient to model the budgets

collectively, and not State-by-State, to

demonstrate that the intended benefits

of the budgets are achieved.

Commenters who recommended Stateby-State modeling generally argued that

it would indicate that the reductions

from a particular State would have a

relatively small impact downwind,

particularly compared to the impact of

local reductions or reductions from

other upwind States. In general, such a

modeling result could stem from the

relatively small amount of emissions

reductions required of a particular

upwind State under the SIP Call, due to

EPA’s decision to base the budgets on

cost-effective controls rather than, more

expensive controls. However, EPA’s air

quality modeling of the ambient impact

of the required budgets in the upwind

States on downwind nonattainment

(discussed below) shows that even if the

downwind ambient impact of the

required reductions from a particular

upwind State were small, that impact,

when combined with the impact from

the reductions required from other

upwind States, provides meaningful

downwind benefits. Ozone air quality

problems are caused by the collective

contribution from numerous sources

over a large geographic area, so that it

is appropriate to assess the impact of

reductions from a particular upwind

State in combination with reductions

from other upwind States. The

downwind air quality benefits from

these upwind reductions confirm the

appropriateness of the promulgated

budgets.

Comment: Commenters stated that

EPA should have modeled alternative

control options to determine if less

stringent controls, either applied

uniformly or on a subregional basis (i.e.,

multi-State subregional variations in

control levels), would provide air

quality benefits essentially equivalent to

EPA’s proposal. In addition,

commenters submitted a considerable

number of new modeling analyses

intended to show that (a) sufficient

downwind ozone benefits can be

achieved with control levels less

stringent than those associated with

EPA’s proposal; (b) controls applied in

certain upwind States, when examined

on a State-by-State basis, do not provide

‘‘significant’’ benefits in any downwind

nonattainment area; and/or (c) NOX

controls increase ozone locally in some

areas and these increases are greater

than the predicted decreases. In

addition to new control strategy

modeling, commenters submitted

modeling that pertains to the finding of

significant contribution. The EPA’s

responses to this modeling are

discussed in Section II.C., Weight of

Evidence Determination of Covered

States and in the Response to Comment

document.

Response: In response to the

comments on the need to model

alternative controls, EPA has modeled

alternative budgets based on several

EGU and non-EGU control options. For

the most part, these alternative budgets

were modeled regionwide in order to

assess, as discussed above, the benefits

considering both downwind and

upwind emissions reductions,

collectively. Further, as discussed

below, EPA modeled several other types

of scenarios including runs to assess the

impacts of the proposal applied in

upwind States on several downwind

areas. The EPA’s modeling analyses are

summarized below and described in

detail in the Air Quality Modeling TSD.

Regarding the new control strategy

modeling submitted by commenters,

EPA has reviewed this information in

the same way it reviewed the new

modeling on ‘‘significant contribution’’,

as described in Section II.C., Weight of

Evidence Determination of Covered

States. Specifically, EPA reviewed the

commenters’ modeling to determine and
Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations 57441

assess (a) the technical aspects of the

models that were applied; (b) the

treatment of emissions inventories; (c)

the types of episodes modeled; (d) the

methods for aggregating, analyzing, and

presenting the results; (e) the

completeness and applicability of the

information provided; and (f) whether

the technical evidence supports the

arguments made by the commenters. A

summary of this review is discussed

next. For the most part, the commenters

used either the UAM–V model and/or

the CAMX model to assess the relative

impacts of various NOX control

strategies. As discussed in Section II.C.

Weight of Evidence Determination of

Covered States, modeling results from

both models are viewed by EPA as

technically acceptable. Concerning the

emissions used for modeling, most

commenters stated that they used the

EPA SNPR or IPM-derived 2007 Base

Case emissions as a starting point for

developing emissions for the control

scenarios. However, the commenters did

not provide emissions data summaries

in order for EPA to confirm which

inventories were used in the modeling.

Also, the commenters did not document

in detail how they applied the controls

to the emissions inventory.

Most of the control strategy modeling

submitted by commenters was

performed for the July 1995 episode

although a few commenters performed

modeling for all four OTAG episodes

and one commenter provided modeling

for a non-OTAG episode in June of

1991. As discussed in Section II.C., and

in the Response to Comment document,

EPA’s ability to fully evaluate and

utilize the modeling submitted by

commenters was hampered in some

cases because only limited information

on the results was provided.

The EPA considered the strengths and

limitations in the commenters’

modeling analyses in evaluating

whether the technical evidence

presented in the comments supports the

arguments made by the commenters. A

detailed review of the commenters’

modeling is contained in the Response

to Comment document. In general, this

review indicates that (a) downwind

ozone benefits increase as greater NOX

controls are applied to sources in

upwind States, (b) emissions reductions

at the level of the SIP Call, even when

evaluated on an individual State-byState basis, reduce ozone in downwind

nonattainment areas, (c) the net benefits

of NOX control at the level of the SIP

Call outweigh any local disbenefits, and

(d) upwind NOX reductions tend to

mitigate local disbenefits in downwind

areas. Thus, based on this evaluation,

EPA generally found that the submitted

modeling did not refute the overall

conclusions EPA has drawn concerning

the impacts of NOX emissions in the

relevant geographic areas. However,

because the extent and level of detail in

the information presented by the

commenters was, in many cases, limited

and/or qualitative, the EPA decided to

model a number of alternative control

scenarios for all four OTAG episodes.

The results of EPA’s modeling of the

impacts of alternative NOX controls are

described next.

C. Assessment of Alternative Control

Levels

As indicated above, EPA has

remodeled the Base Case and Statewide

budgets using updated EGU emissions

which do not exceed the capacity of

individual units. In addition, EPA has

performed modeling of various

alternative EGU and non-EGU control

options. Further, EPA has modeled the

benefits in selected downwind areas of

the budgets applied in upwind States.

The results of EPA’s modeling analyses

are summarized below and described in

more detail in the Air Quality Modeling

TSD.

1. Scenarios Modeled

As part of EPA’s assessment, a 2007

SIP Call Base Case (hereafter referred to

as the ‘‘Base Case’’) and eight emissions

scenarios were modeled, as listed in

Table IV–1. The first four scenarios (i.e.

‘‘0.25’’, ‘‘0.20’’, ‘‘0.15t’’, and ‘‘0.12’’)

were designed to evaluate alternative

EGU and non-EGU controls applied

uniformly in all 23 jurisdictions. For

each of these four scenarios, EGU

emissions were determined assuming a

cap-and-trade program across all 23

jurisdictions. The 0.15t scenario reflects

the SIP Call proposal for both non-EGU

and EGU sources. Note that non-EGU

controls were modeled at the level of

the proposal for all scenarios except for

the 0.25 scenario for which less

stringent controls were assumed.

TABLE IV–1.—EMISSIONS SCENARIOS MODELED

Base Case:

2007 SIP Call Base Case 1

Point Sources: CAA Controls.

Area Sources: OTAG ‘‘Level 1’’ Controls.

Highway Vehicles: OTAG ‘‘Level 0’’ Controls.

Control scenarios Electricity generation units—EGUs Non-EGU point sources 2

0.25 ..................................... 0.25 lb/mmBtu, interstate trading .................................... 60% reduction for large sources.

0.20 ..................................... 0.20 lb/mmBtu, interstate trading .................................... 70% reduction for large sources, RACT for medium

sources2.

0.15t .................................... 0.15 lb/mmBtu, interstate trading .................................... 70% reduction for large sources, RACT for medium

sources.

0.12 ..................................... 0.12 lb/mmBtu, interstate trading .................................... 70% reduction for large sources, RACT for medium

sources.

0.15nt .................................. 0.15 lb/mmBtu, intrastate trading .................................... 70% reduction for large sources, RACT for medium

sources.

Downwind Scenarios for Analysis of ‘‘Transport’’:

(1) 0.15nt EGU and non-EGU controls in the Northeast 3; 2007 Base Case emissions elsewhere.

(2) 0.15nt EGU and non-EGU controls in Georgia; 2007 Base Case emissions elsewhere.

(3) 0.15nt EGU and non-EGU controls in Illinois, Indiana, and Wisconsin; 2007 Base Case emissions elsewhere.

1See Table IV–2 for a listing of Base Case control measures.

2 Reductions are from 2007 ‘‘uncontrolled’’ emissions. Non-EGU sources >250mmBtu/hr are considered as ‘‘large’’; sources <250mmBtu/hr,

but >1tpd are considered as ‘‘medium’’. The non-EGU point source controls assumed for purposes of this modeling do not match the levels assumed for the purpose of calculating the final budgets. 3 Northeast includes Connecticut, Delaware, District of Columbia, Maryland, Massachusetts, New Jersey, New York, Pennsylvania, and Rhode

Island.
57442 Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations

The EPA also modeled a 0.15

intrastate trading scenario, ‘‘0.15nt’’,

which was constructed with EGU

emissions that meet each State’s budget

without interstate trading. In developing

the EGU emissions for this scenario,

intrastate trading among sources in a

State was allowed to occur. The benefits

of the 0.15nt scenario compared to those

from the 0.15t scenario were examined

to determine whether an interstate

trading program would affect the overall

benefits of the proposal.

The last three scenarios in Table IV–

1 were designed to evaluate the

downwind benefits resulting from

reductions in transport due to the

budgets in upwind States. Each of these

scenarios constitutes a separate

modeling run that applies the 0.15nt

scenario in a different downwind area.

For example, in the ‘‘nt15NE’’ scenario,

the 0.15nt emissions budgets were

applied only in those Northeast States

subject to the SIP Call. The predictions

from each of these three modeling runs

for specific downwind areas were

compared to the Base Case to estimate

the impacts of the budgets applied only

within the downwind area. The

predictions from these three runs were

then compared to the 0.15nt scenario

across all 23 jurisdictions to estimate

the additional benefits in each

downwind area due to reductions in

transport resulting from the budgets

applied in both upwind and downwind

States.

2. Emissions for Model Runs

As indicated in Table IV–1, Base Case

emissions for area sources (including

nonroad), highway vehicles, and nonEGU sources represent a combination of

OTAG emissions data for various

control levels. This includes CAA

controls on non-EGU point sources,

OTAG ‘‘level 1’’ controls on area

sources, and ‘‘level 0’’ controls on

highway vehicles. The control measures

included in the Base Case for each

source category are listed in Table IV–

2. These modeling runs were performed

before changes were made to the

inventory in response to comments. For

the 23 jurisdictions as a whole, the Base

Case NOX emissions that were modeled

are 2 percent higher than the final Base

Case emissions that reflect changes

made in response to comments.

TABLE IV–2.—2007 SIP CALL BASE CASE CONTROLS

EGUs:

Title IV Controls [ phase 1 and 2 ].

—250 Ton PSD and NSPS.

—RACT & NSR in non-waived NAAs.

Non-EGU Point:

—NOX RACT on major sources in non-waived NAAs.

—250 Ton PSD and NSPS.

—NSR in non-waived NAAs.

—CTG and Non-CTG VOC RACT at major sources in NAAs and OTR.

—New Source LAER.

Stationary Area:

—Two Phases of VOC Consumer and Commercial Products and One Phase of Architectural Coatings controls.

—VOC Stage 1 and 2 Petroleum Distribution Controls in NAAs.

—VOC Autobody, Degreasing and Dry Cleaning controls in NAAs.

Nonroad Mobile:

Fed Phase II Small Eng. Stds.

—Fed Marine Eng. Stds.

—Fed Nonroad Heavy-Duty (≤=50 hp) Engine Stds—Phase 1.

—Fed RFG II (statutory and opt-in areas).

—9.0 RVP maximum elsewhere in OTAG domain.

—Fed Locomotive Stds (not including rebuilds).

—Fed Nonroad Diesel Engine Stds—Phases 2 and 3.

Highway Vehicles:

—National LEV.

—Fed RFG II (statutory and opt-in areas).

—9.0 RVP maximum elsewhere in OTAG domain.

—High Enhanced I/M (serious and above NAAs).

—Low Enhanced I/M for rest of OTR.

—Basic I/M (mandated NAAs).

—Clean Fuel Fleets (mandated NAAs).

—On-board vapor recovery.

—HDV 2 gm std.

Rate of Progress Requirements:

—Effectively, ROP through 1999.

Note that area and mobile source

emissions were held constant at Base

Case levels in all scenarios. The Base

Case emissions for EGUs were obtained

from simulations of IPM which

projected 1996 electric generation to

2007 based on economic assumptions,

unit specific capacity, and the

requirements in Title I and Title IV of

the CAA. The Base Case emissions that

were modeled for the EGU sector are 4

percent higher than the final Base Case

emissions for this sector. The EGU

emissions estimates for each of the

control scenarios in Table IV–1 were

also derived using the IPM. Table IV–3

summarizes the emissions reductions

provided by the control scenarios

compared to the Base Case. The

development of emissions data for air

quality modeling is further described in

the Air Quality Modeling TSD.
Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations 57443

TABLE IV–3.—SUMMARY OF NOX EMISSIONS REDUCTIONS

Region 1 0.25 0.20 0.15t 0.12 0.15nt

Percent Reduction in Point Source NOX Emissions From 2007 SIP Call Base Case

Northeast .............................................................................. 29 39 49 52 46

Midwest ................................................................................. 40 51 59 65 58

Southeast .............................................................................. 35 49 54 61 56

SIP Call 2 ............................................................................... 37 48 57 62 57

Percent Reduction in Total NOX Emissions From 2007 SIP Call Base Case

Northeast .............................................................................. 13 18 22 24 21

Midwest ................................................................................. 22 28 33 36 32

Southeast .............................................................................. 19 26 29 32 30

SIP Call 2 ............................................................................... 20 26 30 33 30

1The Northeast includes Connecticut, Delaware, District of Columbia, Maryland, Massachusetts, New Jersey, New York, Pennsylvania, and

Rhode Island; the Midwest includes Illinois, Indiana, Kentucky, Michigan, Missouri Ohio, West Virginia, and Wisconsin; the Southeast includes

Alabama, Georgia, North Carolina South Carolina, Tennessee and Virginia. 2 ‘‘SIP Call’’ includes the total percent reduction over all 23 jurisdictions subject to budgets as part of this notice.

3. Modeling Results

The EPA applied UAM–V for each of

the four OTAG episodes to simulate

ozone concentrations for the Base Case

and each scenario. The results for the

uniform regionwide scenarios are

presented first. This is followed by the

results comparing interstate and

intrastate trading. The results for the

assessment of overall downwind

benefits of the budgets applied in

upwind States is presented last.

The analysis of model predictions

focused 1-hour daily maximum values

and 8-hour daily maximum values

predicted for all 4 episodes. The

rationale for analyzing the model

predictions in this way is discussed in

Section II.C. Each of the control

scenarios was evaluated using the four

‘‘metrics’’ listed in Table IV–4. Note that

the model predictions used in

calculating the metrics were restricted

to those 1-hour values >=125 ppb and 8-

hour values >=85. Model predictions

less than these concentrations were not

included in the analysis.

TABLE IV–4.—AIR QUALITY METRICS

Metric 1: Exceedances ....................................... The number of values above the concentration level of NAAQS.1

Metric 2: Ozone Reduced-ppb ............................ The magnitude and frequency of the ‘‘ppb’’ reductions in ozone.

Metric 3: Total ppb Reduced .............................. The total ‘‘ppb’’ reduced by a given scenario, not including that portion of the reduction that

occurs below the level of the NAAQS.

Metric 4: Population-Weighted Total ppb Reduced.The same as Metric 3, except that the ozone reductions are weighted by the population in the

grid cell in which the reductions occur.

1 1-hour values >=125 ppb; 8-hour values >=85 ppb.

A full description of these metrics and

the procedures for selecting

‘‘nonattainment’’ receptors for

calculating the metrics can be found in

the Air Quality Modeling TSD. In brief,

‘‘nonattainment’’ receptors for the 1-

hour analysis include those grid cells

that (a) are associated with counties

designated as nonattainment for the 1-

hour NAAQS and (b) have 1-hour Base

Case model predictions >=125 ppb.

These grid cells are referred to as

‘‘designated plus modeled’’

nonattainment receptors. Using these

receptors, the metrics were calculated

for each 1-hour nonattainment area as

well as for each State. To calculate the

metrics by State, the ‘‘nonattainment’’

receptors in that State were pooled

together.

For the 8-hour analysis,

‘‘nonattainment’’ receptors include

those grid cells that (a) are associated

with counties currently violating the 8-

hour NAAQS and (b) have 8-hour Base

Case model predictions >=85 ppb. These

grid cells are referred to as ‘‘violating

plus modeled’’ nonattainment receptors.

The metrics were calculated on a Stateby-State basis for the 8-hour analyses.

In general, the four metrics lead to

similar overall conclusions. The results

for the full set of receptor areas (i.e.,

‘‘designated plus modeled’’ for the 1-

hour NAAQS and ‘‘violating plus

modeled’’ for the 8-hour NAAQS) are

provided in the Air Quality Modeling

TSD for all four metrics. In this

preamble, Metrics 1 and 3 are presented

to illustrate the results.

a. Impacts of Alternative Controls.

The impacts on ozone concentrations of

the 0.15t scenario and each of the

alternative scenarios are provided by

region (i.e., Midwest, Southeast, and

Northeast) in Tables IV–5 and IV–6 for

Metrics 1 and 3, respectively. The

complete set of data for individual

States and 1-hour nonattainment areas

is provided in the Air Quality Modeling

TSD. Table IV–5 shows the percent

reduction in the number of exceedances

across all four episodes between each

control scenario and the Base Case.

Table IV–6 shows the percent reduction

in total ozone above the NAAQS

provided by each scenario, compared to

the total ozone above the NAAQS in the

Base Case.
57444 Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations

61The rationale for analyzing the impacts over

Lake Michigan is discussed in Section II.C, Weight

of Evidence Determination of Covered States.

TABLE IV–5.—RESULTS FOR METRIC 1: NUMBER OF EXCEEDANCES

0.25 0.20 0.15t 0.12 0.15nt

Percent Reduction in the Number of Exceedances 1-Hour Daily Maximum >=125 ppb

Midwest ................................................................................. 25 32 38 43 38

Southeast .............................................................................. 23 33 34 40 36

Northeast .............................................................................. 24 31 36 39 36

SIP Call Total ........................................................................ 24 31 36 40 37

Percent Reduction in the Number of Exceedances 8-Hour Daily Maximum >=85 ppb

Midwest ................................................................................. 35 44 50 54 49

Southeast .............................................................................. 30 40 46 51 48

Northeast .............................................................................. 26 34 41 44 41

SIP Call Total ........................................................................ 30 39 45 49 45

TABLE IV–6.—RESULTS FOR METRIC 3: TOTAL ‘‘PPB’’ REDUCED

0.25 0.20 0.15t 0.12 0.15nt

Total ‘‘ppb’’ Reduced Compared to the Total ‘‘ppb’’ Above NAAQS in Base Case 1 1-Hour Daily Maximum >=125 ppb

Midwest ................................................................................. 31 39 45 49 44

Southeast .............................................................................. 27 37 39 44 41

Northeast .............................................................................. 25 32 37 40 37

SIP Call Total ........................................................................ 27 35 40 43 40

Total ‘‘ppb’’ Reduced Compared to the Total ‘‘ppb’’ Above NAAQS in Base Case 8-Hour Daily Maximum >=85 ppb

Midwest ................................................................................. 35 42 48 52 47

Southeast .............................................................................. 33 44 49 53 50

Northeast .............................................................................. 28 37 43 46 43

SIP Call Total ........................................................................ 31 40 46 50 46

1The values in this table were calculated by dividing the Total ‘‘ppb’’ Reduced in the control scenario by the Total ‘‘ppb’’ above the NAAQS in

the Base Case. These values represent the percent of total ozone above the NAAQS in the Base Case that is reduced by the control scenario.

The results indicate that the 0.15t

scenario provides substantial reductions

in both 1-hour and 8-hour ozone

concentrations in all three regions.

In the Midwest the 0.15t scenario

provides a 38 percent reduction in 1-

hour exceedances and a 45 percent

reduction in ‘‘total ozone’’ >=125 ppb.

The regionwide Midwest reductions in

8-hour exceedances and ‘‘total ozone’’

>=85 ppb are 45 percent and 50 percent,

respectively. Considering individual 1-

hour nonattainment areas in this region,

the reduction in exceedances due to the

0.15t controls are 36 percent over Lake

Michigan,61 73 percent in Southwest

Michigan, and 54 percent in Louisville.

The corresponding reductions in ‘‘total

ozone’’ >=125 ppb are 44 percent over

Lake Michigan, 81 percent in southwest

Michigan, and 64 percent in Louisville.

The results for other areas are contained

in the Air Quality Modeling TSD.

In the Southeast, 1-hour exceedances

are reduced by 39 percent and the ‘‘total

ozone’’ >=125 ppb by 34 percent.

Considering individual nonattainment

areas in the Southeast, the 0.15t

scenario provides a 36 percent

reduction in 1-hour exceedances in

Atlanta and a 39 percent reduction in

exceedances in Birmingham. The

reduction in ‘‘total ozone’’ >=125 ppb is

41 percent in Atlanta and 54 percent in

Birmingham. The overall regionwide

ozone benefits across the Southeast are

also large for the 8-hour NAAQS. For

example, the number of 8-hour

exceedances in this region is reduced by

46 percent with the 0.15t scenario.

In the Northeast, 0.15t provides a 37

percent reduction in 1-hour

exceedances and a 34 percent reduction

in ‘‘total ozone’’ >=125 pp. For

individual nonattainment areas in the

Northeast, the reductions in both

Metrics 1 and 3 range from

approximately 25 percent in

Washington, DC up to 100 percent in

Pittsburgh. For the serious and severe 1-

hour nonattainment areas along the

Northeast Corridor from Washington,

DC to Boston, the 1-hour reductions

vary from city to city, but are generally

in the range of 25 percent to 55 percent.

The regionwide reductions in 8-hour

exceedances and ‘‘total ozone’’ >=85

ppb in the Northeast are above 40

percent.

In general, results from the scenarios

evaluated demonstrate that the larger

the reduction in NOX emissions, the

greater the overall ozone benefit. As

indicated in Table IV–5 and IV–6, the

0.25 and 0.20 scenarios generally do not

provide the same level of reduction as

the 0.15t scenario in any of the three

regions, whereas the 0.12 scenario

provides additional ozone benefits

beyond 0.15t in all three regions. Also,

the results indicate that even with the

most stringent control option

considered, nonattainment problems

requiring additional local controls may

continue in some areas currently

violating the NAAQS.

The impact on ozone reductions of a

trading program versus meeting the

budgets in each State can be seen by

comparing the results for the 0.15t and

0.15nt scenarios. The data in Tables IV–

5 and IV–6 indicate that there is no

overall loss of ozone benefits for either

1-hour or 8-hour concentrations across

the 23 jurisdictions due to trading. On

a regional basis, the benefits of interstate

and intrastate trading at the 0.15 control

level are essentially the same in the

Northeast and Midwest and slightly less

with interstate trading in the Southeast.
Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations 57445

62As described in the Air Quality Modeling TSD,

emissions from the intrastate trading scenario rather

than the interstate trading scenario were used for

the analysis of upwind controls in order to avoid

any potentially confounding effects of small

changes in the downwind emissions between the

downwind control scenario and the downwind plus

upwind control scenario due to interstate trading.

As indicated in the summary of

comments, several commenters stated

that there would be local disbenefits

due to the EPA proposal that would

outweigh any benefits. The modeling

runs discussed here shed light on the

issue. Of the four metrics examined by

EPA, Metrics 3 and 4 (i.e., ‘‘Total ppb

Reduced’’ and ‘‘Population-Weighted

Total ppb Reduced’’) are most

appropriate for identifying any net

disbenefits because the ozone decreases

and any increases (disbenefits) are

considered in calculating each of these

metrics. The metrics will have negative

values for situations in which the total

disbenefits are greater than the total

benefits. The EPA examined the 1-hour

estimates for these metrics for each 1-

hour nonattainment area and the 8-hour

estimates by State to identify any areas

in which the modeling indicated a net

disbenefit. The results indicate that the

only net disbenefit predicted in any of

the scenarios was in Cincinnati for the

1-hour NAAQS. However, these

disbenefits occurred only in the 0.25

and 0.20 scenarios. In the 0.15t scenario,

there is a net 32 percent benefit in

Cincinnati with Metric 3 and a net

benefit of 23 percent with Metric 4.

There were no net Statewide 8-hour

disbenefits in any of the scenarios

examined by EPA.

b. Impacts of Upwind Controls on

Downwind Nonattainment. The impacts

of the budgets applied in upwind States

on downwind ozone in the (a) the

Northeast, (b) Georgia, and (c) IllinoisIndiana-Wisconsin, were evaluated by

comparing the 0.15nt scenario to the

three downwind transport assessment

scenarios listed in Table IV–1. In each

of these three scenarios, EPA modeled

the 0.15nt option in one of the

downwind areas with the Base Case

emissions applied in the rest of the

OTAG region.62 The results of each

downwind control run were compared

to the Base Case in order to assess the

benefits of the controls applied within

those areas (i.e., the downwind areas).

Similarly, the predictions for the 0.15nt

regionwide scenario were compared to

the Base Case to estimate the benefits in

each area of the downwind plus upwind

controls. The benefits of the upwind

controls were determined by calculating

the difference between the benefits of

the downwind controls compared to the

benefits of the downwind plus upwind

controls. The results are provided in

Table IV–7. The following is an example

of how the benefits of upwind controls

were calculated for Metric 1 (i.e.,

number of exceedances). In the

Northeast, there were 1052 grid-day

exceedances of the 1-hour NAAQS

predicted in the Base Case scenario. In

the downwind control scenario (i.e.,

0.15nt applied in the Northeast only),

the number of exceedances declined to

827 grid-days which represents a 21

percent reduction in exceedances from

the Base Case due to controls in the

Northeast. In the downwind plus

upwind scenario, the number of 1-hour

exceedances declined even further to

670 grid-days which is a 36 percent

reduction from the Base Case. Therefore,

the upwind controls provide a 15

percent reduction in 1-hour

exceedances in the Northeast (i.e., 36

percent versus 21 percent).

For Metric 3 (i.e., Total ‘‘ppb’’

Reduced), the impact of upwind

controls on downwind ozone was

determined using two approaches. The

first approach is similar to the

procedures followed described above for

exceedances. For example, in the

Northeast the total ppb >=125 ppb

(across all grids and days) in the Base

Case was 14,724 ppb. In the downwind

control scenario the total ppb reduced

by these controls was 3289 ppb which

represents a 22 percent reduction (i.e.,

3289 ppb divided by 14,724 ppb) in

total ppb >=125 ppb. In the downwind

plus upwind control scenario, the total

ppb reduced was 5500 ppb which

represents a 37 percent reduction in

total ppb >=125 ppb in the Base Case.

Therefore, the upwind controls provide

a 15 percent reduction in total ppb

>=125 ppb (i.e., 37 percent versus 22

percent). The results for Metric 3

calculated using this first approach are

presented in Table IV–7.

A second approach to analyze the

benefits of upwind controls using

Metric 3 is to determine the fraction or

percentage of the total reduction from

downwind plus upwind controls that

comes from just the upwind controls.

This is determined by first subtracting

the ppb reduced by downwind controls

from the ppb reduced by downwind

plus upwind controls. This difference

provides an estimate of the portion of

the reduction due to upwind controls.

Then, the portion of the reduction due

to upwind controls is divided by the

reduction from downwind plus upwind

controls to estimate the percent of

reduction due to the upwind controls

only. For example, in the Northeast the

1-hour total ppb reduced by the

downwind plus upwind controls is

5500 ppb and the total ppb reduced by

the downwind controls is 3289 ppb. The

difference (2211 ppb) is the estimated

amount of reduction due to upwind

controls. Thus, in this example, the

upwind controls provide 40 percent

(i.e., 2211 ppb divided by 5500 ppb) of

the total ppb reduction in the

downwind plus upwind regionwide

scenario. The results for Metric 3 using

this second approach for estimating the

impacts of upwind controls are

provided in Table IV–8.

1-hour daily max 8-hour daily max

DW 1 DW + UW 1 UW 1 DW DW + UW UW

Percent Reduction in Exceedances

Northeast ................................................... 21 36 15 18 40 22

Lake MI ..................................................... 29 36 7 11 17 6

IL/IN/WI ..................................................... 35 50 15 27 57 30

Atlanta ....................................................... 30 39 9 2 NA NA NA

Georgia 3 ................................................... 30 39 9 15 27 12

Percent Reduction in Total ‘‘ppb’’ Above the NAAQS

Northeast ................................................... 22 37 15 23 43 20

Lake MI ..................................................... 39 44 5 20 28 8

IL/IN/WI ..................................................... 17 33 16 32 62 30

Atlanta ....................................................... 37 43 6 NA NA NA
57446 Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations

1-hour daily max 8-hour daily max

DW 1 DW + UW 1 UW 1 DW DW + UW UW

Georgia ..................................................... 37 43 6 25 35 10

1 ‘‘DW’’ denotes the reductions due to the downwind controls; ‘‘DW + UW’’ denotes the reductions due to controls applied regionwide in upwind

plus downwind areas; and ‘‘UW’’ denotes the incremental additional reduction in exceedances. 2 NA: The metrics for the 8-hour NAAQS were not calculated for individual 1-hour nonattainment areas.

3The 1-hour results for Georgia are the same as for Atlanta because Atlanta is the only 1-hour nonattainment area in that State.

TABLE IV–8.—PERCENT OF THE TOTAL PPB ABOVE THE NAAQS THAT IS REDUCED DUE TO UPWIND CONTROLS

1-hour daily

max (percent)

8-hour daily

max (percent)

Northeast .................................................................................................................................................................. 40 48

Lake MI .................................................................................................................................................................... 12 27

IL/IN/WI .................................................................................................................................................................... 49 48

Atlanta ...................................................................................................................................................................... 14 NA

Georgia ..................................................................................................................................................................... 14 28

In the following discussion of the

impacts of upwind controls on ozone in

the three downwind areas, the results

for Metric 3 focus on the second

approach for calculating upwind

impacts using this metric since the

results based on the first approach are

similar to those for Metric 1, as

indicated in Table IV–7.

In the Northeast, the upwind controls

provide a 15 percent reduction in 1-

hour exceedances and a 22 percent

reduction in 8-hour exceedances. The

results in Table IV–8 indicate that

upwind controls provide 40 percent or

more of the total ppb reduction from the

downwind plus upwind control

scenario for both the 1-hour and 8-hour

NAAQS. Considering the results for

several 1-hour nonattainment areas in

the Northeast, the upwind controls

reduce the number of 1-hour

exceedances by 21 percent in Baltimore,

12 percent in Philadelphia, 12 percent

in New York City, 19 percent in Greater

Connecticut, and 3 percent in Boston.

The percent of the total ppb reduction

from the downwind plus upwind

controls that is due to the upwind

controls alone is 48 percent in

Baltimore, 29 percent in Philadelphia,

38 percent in New York City, 47 percent

in Connecticut, and 25 percent in

Boston. The results for all of the

Northeast 1-hour nonattainment areas

are provided in the Air Quality

Modeling TSD.

The impacts of upwind controls on

nonattainment in Georgia were

examined using the 0.15nt scenario in

Georgia versus the Base Case scenario

and the scenario with 0.15nt applied

regionwide. The results, as shown in

Table IV–7, indicate that the upwind

controls are predicted to reduce the

number of 1-hour exceedances in

Atlanta by 9 percent. Also, in Atlanta,

14 percent of the 1-hour total ppb above

the NAAQS reduced by the downwind

plus upwind regionwide scenario is due

to the controls applied in upwind

States. For the 8-hour NAAQS, the

upwind controls provide a 12 percent

reduction in 8-hour exceedances within

the State of Georgia. The upwind

controls provide 28 percent of the total

ppb reduction in the downwind plus

upwind regionwide control scenario.

To assess the benefits in IllinoisIndiana-Wisconsin due to upwind

controls, EPA examined the data for the

Lake Michigan receptor area and for the

three States, combined. The discussion

of results focuses on the Lake Michigan

receptor area. The data for this area and

the three States are provided in Table

IV–7. For the Lake Michigan receptor

area, there is a 7 percent reduction in 1-

hour exceedances and a 6 percent

reduction in 8-hour exceedances due to

upwind controls. The upwind controls

provide 12 percent of the total 1-hour

reduction and 27 percent of the total 8-

hour reduction that results from the

downwind plus upwind regionwide

controls. In Illinois, Indiana, and

Wisconsin, the reduction in 1-hour and

8-hour exceedances due to upwind

controls are larger than over Lake

Michigan (i.e., 15 percent and 30

percent for 1-hour and 8-hour

exceedances, respectively). The upwind

controls provide nearly 50 percent of

the total ppb reductions associated with

the downwind plus upwind regionwide

control scenario for both the 1-hour and

8-hour NAAQS.

Based on the results discussed above,

EPA believes that the controls in today’s

rulemaking applied in upwind areas

will reduce the number of 1-hour and 8-

hour exceedances in downwind

nonattainment areas. The analysis

indicates that in downwind areas, a

substantial portion of the 1-hour and 8-

hour ozone reductions provided by the

regionwide application of these controls

are due to those controls in upwind

areas.

c. Summary of Findings. The EPA has

performed an air quality assessment to

estimate the ozone benefits of the

proposal and several alternative uniform

regionwide control levels. In addition,

EPA examined the overall benefits in

several major downwind nonattainment

areas of the application of the proposal

in upwind States. The results of EPA’s

assessment corroborate and extend the

findings presented in the SNPR. The

major findings are as follows: (1) The

NOX emissions reductions associated

with the proposed Statewide budgets

are predicted to produce large

reductions in (a) 1-hour concentrations

>=125 ppb in areas which are currently

nonattainment for the 1-hour NAAQS

and which would likely continue to

have a 1-hour nonattainment problem in

the future without the SIP call budget

reductions, and (b) 8-hour

concentrations >=85 ppb in areas which

currently violate the 8-hour NAAQS and

which would likely continue to have an

8-hour ozone problem in the future

without the SIP call budget reductions.

(2) The more NOX emissions are

reduced, the greater the benefits in

reducing ozone concentrations. There

does not appear to be any ‘‘leveling off’’

of benefits within the range of NOX

reductions associated with EPA’s

proposal. That is, NOX reductions at

control levels less than EPA’s proposal

provide fewer air quality benefits than

the proposal and NOX reduction greater

than the proposal provide more air

quality benefits.
Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations 57447

(3) Any disbenefits due to the NOX

reductions associated with the budgets

are expected to be very limited

compared to the extent of the benefits

expected from these budgets.

(4) There are likely to be benefits in

major nonattainment areas due to the

downwind application of controls in the

proposed budgets. Reductions in ozone

transport associated with the collective

application of the budgets in upwind

States are expected to provide

substantial ozone benefits in downwind

areas, beyond what is provided by the

budgets applied in the downwind areas

alone. Together, the downwind

reductions and transport reductions

from upwind controls will provide

significant progress toward attainment

in major nonattainment areas within the

OTAG region. However, even with the

most stringent control option

considered, nonattainment problems

requiring additional local control

measures may continue in some areas

currently violating the NAAQS.

V. NOX Control Implementation and

Budget Achievement Dates

A. NOX Control Implementation Date

In the NPR, the EPA proposed to

mandate NOX emissions decreases in

each affected State leading to a budget

based on reductions to be achieved from

both Federal and State measures. The

EPA further proposed that the required

SIP revisions for achieving the portion

of the NOX reduction from State

measures be implemented by no later

than September 2002. The EPA also

requested comment on a range of

compliance dates between September

2002 and September 2004.

The EPA stated that this range of

compliance dates is consistent with the

requirement for severe 1-hour

nonattainment areas to attain the

standard no later than 2005 (for severe15 areas) or 2007 (for severe-17 areas).

With respect to the 8-hour ozone

standard, EPA stated that the CAA

provides for attainment within 5 years

of designation as nonattainment, which

must occur no later than July 2000, with

a possible extension of up to 10 years

following designation as nonattainment.

The EPA stated that the range of

implementation dates—from September

2002 to September 2004—is consistent

with the attainment time frames for the

8-hour standard (62 FR 60328–29). For

the reasons described in Section III,

below, the applicable attainment date

for all affected downwind areas is ‘‘as

expeditiously as practicable,’’ but no

later than certain prescribed dates. In

many cases, the date for achieving the

upwind reductions will make the

difference as to when downwind States

will attain. Thus, it is appropriate for

EPA to require the upwind reductions to

be achieved as expeditiously as

practicable. Subsection 1., below,

analyzes the earliest date feasible for

achieving the upwind reductions.

1. Practicability

After reviewing the comments and

analyzing the feasibility of

implementing the NOX controls

assumed for purposes of developing the

State emissions budgets, as well as other

measures which States may choose to

rely on to meet the rule, the EPA is

today determining that the required

implementation date must be by no later

than May 1, 2003. The Agency received

many comments on the feasibility of

installing appropriate control

technology by 2003, and the succeeding

paragraphs address many of the

significant comments submitted on this

topic.

Some commenters asserted that a

compliance deadline of September 2002

is infeasible for completing the

installation of the assumed NOX

controls. Some of these commenters

argued that there are not enough trained

workers, engineering services or

materials and equipment to install NOX

controls by the September 2002

deadline. Other commenters expressed

concern that utilities will not have

sufficient time to install NOX controls

without causing electrical power

outages; these commenters stated that

such power outages would have adverse

impacts on the reliability of the

electricity supply. Commenters also

expressed concern that retrofitting NOX

controls would require increasing the

operation of less efficient units, which

would increase compliance costs.

In response to these comments, the

Agency has conducted a detailed

examination of the feasibility of

installing the NOX controls that EPA

assumed in constructing the emissions

budgets for the affected States

(hereinafter, the ‘‘assumed control

strategy’’). See the technical support

document ‘‘Feasibility of Installing NOX

Control Technologies By May 2003,’’

EPA, Office of Atmospheric Programs,

September 1998. The Agency’s findings

are summarized below. Based on these

findings, the EPA believes that the

compliance date of May 1, 2003 for NOX

controls to be installed to comply with

the NOX SIP call is a feasible and

reasonable deadline. The Agency is also

providing some compliance flexibility

to States for the 2003 and 2004 ozone

seasons by establishing State

compliance supplement pools as

described above in Section III.F.6.

The EPA’s projections for the

assumed control strategy include postcombustion controls (Selective Catalytic

Reduction [SCR] and Selective

Noncatalytic Reduction [SNCR]) and

combustion controls (e.g., low NOX

burners, overfire air, etc.)

a. Combustion Controls. In general,

the implementation of combustion

controls should be readily accomplished

by May 1, 2003 for the following

reasons. First, there is considerable

experience with implementing

combustion controls. Combustion

control retrofits on over 230 utility

boilers, accounting for over 75 GWe of

capacity under the title IV NOX

program, took place within 4 years (i.e.,

from 1992 through 1995). Moreover, the

combustion retrofits under Phase I of

the Ozone Transport Commission’s

Memorandum of Understanding were

completed in the same time frame. As

a result of this experience, the sources

and permitting agencies are familiar

with the installation of combustion

controls. This familiarity should result

in relatively short time frames for

completing technology installations and

obtaining relevant permits.

Second, combustion controls are

constructed of commonly available

materials such as steel, piping, etc., and

do not require reagent during operation.

Therefore, the EPA does not expect

delays due to material shortages to

occur at sites implementing these

controls.

Third, there are many vendors of

combustion control technology. These

vendors should have ample capacity to

meet the NOX SIP call needs because

they were able to satisfy significant

installation needs during the period

1992 through 1995, as mentioned above.

Since then these vendors have had

relatively few installation needs to fill.

Therefore, it is reasonable to expect

that implementation of post-combustion

controls, not combustion controls,

would determine the schedule for

implementing all of the projected NOX

controls.

b. Post-Combustion Controls. Tables

V–1 and V–2 present the Agency

projections of how many electricity

generating units and industrial sources,

respectively, would need to be

retrofitted with post-combustion NOX

controls under the assumed control

strategy.
57448 Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations

TABLE. V–1.—ELECTRICITY

GENERATING UNITS

NOX Control

Projected

No. of installations

Coal SCR .................................. 142

Coal SNCR ............................... 482

Oil/gas SNCR ........................... 15

Total ................................... 639

TABLE. V–2.—NON-ELECTRICITY

GENERATING UNITS

NOX Control

Projected

No. of installations

SCR on coal-fired sources ....... 55

SCR on oil/gas-fired sources .... 225

SCR on other sources .............. 1

Total ................................... 281

SNCR on coal-fired sources ..... 195

SNCR on oil/gas-fired sources 0

SNCR on other sources ........... 40

Total ................................... 235

There are three basic considerations

related to implementation of postcombustion controls (SCR and SNCR) by

the compliance date: (1) Availability of

materials and labor, (2) the time needed

to implement controls at plants with

single or multiple retrofit requirements,

and (3) the potential for interruptions in

power supply resulting from outages

needed to complete installations.

The EPA examined each of these

considerations. An adequate supply of

off-the-shelf hardware (such as steel,

piping, nozzles, pumps, soot blowers,

fans, and related equipment), reagent

(ammonia and urea), and labor would be

available to complete implementation of

post-combustion controls projected

under the assumed control strategy.

However, the catalyst used in the SCR

process is not an off-the-shelf item and,

therefore, requires additional

consideration. Based on the projections

shown in the tables above, the EPA

estimates that about 54,000 to 90,000 m3

of catalyst may be needed in SCR

installations. The EPA has found that

currently the catalyst suppliers can

supply about 43,000 to 67,000 m3 of

catalyst per year. However, of this

supply about 5,000 to 8,000 m3 of

catalyst per year is needed to meet the

requirements of the existing worldwide

SCR installations. Based on these

estimates, the EPA conservatively

concludes that adequate catalyst supply

should be available if SCR installations

were to occur over a period of two years

or more.

In addition, in comments to EPA’s

proposed NOX reduction program, the

Institute of Clean Air Companies (ICAC)

stated that more than sufficient vendor

capacity existed to supply retrofit SCR

catalyst to the sources that would be

controlled by SCR under the assumed

control strategy.

Implementation of a NOX control

technology on a combustion unit

involves conducting facility engineering

review, developing control technology

specifications, awarding a procurement

contract, obtaining a construction

permit, completing control technology

design, installation, testing, and

obtaining an operating permit. The EPA

evaluated the amount of time

potentially needed to complete these

activities for a single unit retrofit and

found that about 21 months would be

needed to implement SCR while about

19 months would be needed to

implement SNCR.

The EPA examined several

particularly complicated

implementation efforts to assure an

accurate and realistic estimate of the

time needed to install SCR and SNCR.

The EPA examined the data and

determined that the assumed control

strategy might lead one plant to choose

to install a maximum of 6 SCRs. In

another instance, a different plant might

choose to install a maximum of 10

SNCRs under the assumed control

strategy. The estimated total time

needed to complete these installations is

34 months for 6 SCR systems and 24

months for 10 SNCR systems.

Finally, the EPA examined the

impact(s) that outages required for

connecting NOX post-combustion

controls to EGUs could potentially have

on the supply of electricity and on the

cost of this rule. The EPA has found

that, generally, connections between a

NOX control system and a boiler can be

completed in 5 weeks or less. This

connection period has been accounted

for in both the single and multi-unit

implementation times presented in the

previous paragraph. On an EGU, the

connection would have to be completed

during an outage period in which the

unit is not operational. The EPA’s

research reveals that currently, on

average, about 5 weeks of planned

outage hours are taken every year at an

electricity generating unit. Therefore,

the EPA expects that connection

between a NOX control system and such

a unit would be completed during one

of these planned outages.

Results of EPA’s analyses reflect that,

even if all of the post-combustion

controls projected in Table V–1 for the

EGUs were to be connected to these

units in one single year, no disruption

in the supply of electricity would occur.

If each of these plants takes the five

week outage in a single block of time,

no cost increase is expected to occur.

However, if a plant divides the five

week outage into two or more periods,

a cost increase of less than one-half of

one percent may be expected. See the

technical support document ‘‘Feasibility

of Installing NOX Control technologies

By May 2003,’’ EPA, Office of

Atmospheric Programs, September

1998.

Based on the estimated timelines for

implementing NOX controls at a plant

and availability of materials and labor,

the EPA estimates that the NOX controls

in the assumed control strategy (which

is one available method for achieving

the required NOX reductions in each

covered State) could be readily

implemented by September 2002,

without causing an adverse impact on

the electricity supply or on the cost of

compliance. The EPA bases this

conclusion on its analysis that the most

complex and time-consuming

implementation effort—one involving 6

SCR systems—would take 34 months,

and that all of the controls could be

installed within this period without

causing any disruptions in the supply of

electricity.

Further, the EPA notes that the

September 27, 1994 OTC NOX

Memorandum of Understanding (MOU)

provides that large utility and nonutility

NOX sources should comply with the

Phase III controls by the year 2003. The

levels of control in the MOU are 75

percent or 0.15 lb/106 btu in the inner

and outer zones of the Northeast OTR,

levels comparable to the controls

assumed in setting the budget for

today’s rulemaking. Moreover, several

States in the Northeast OTR have

submitted SIP revisions implementing

this level of emissions reductions from

NOX sources in those States by May 1,

2003. This further supports the

feasibility of the May 1, 2003

implementation date for these controls.

The EPA has determined that States

would have sufficient time to

implement other NOX control measures

in lieu of the boiler controls described

above. For example, vehicle I/M

programs have historically required no

more than two years to implement,

including the time needed to pass

enabling State legislation and to

construct the necessary emission testing

facilities. The time required to

implement measures to reduce VMT

depends on the nature of the measure,

but many VMT reduction measures

require no more than one or two years

to implement. State opt-ins to the RFG

program have generally required less
Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations 57449

63CAA sections 171(1) and 172(c)(2) (requiring

that nonattainment area SIPs provide for reductions

in emissions that may reasonably be required by the

Administrator for the purpose of ensuring

attainment of the applicable national ambient air

quality standard by the applicable date; 182(b)(1)

and (c)(2)(B) (requiring, respectively, 15 percent

reductions between 1990 and 1996 and additional

3 percent average reductions per year until the

attainment date, unless, among other things, the

plan includes ‘‘all measures that can be feasibly

implemented in the area, in light of technological

achievability’’).

than one year to implement. Even if the

EPA were to determine that supply

considerations warranted a delay in

implementing the opt-in request, the

delay cannot exceed two years.

States can also take advantage of the

NOX-reducing benefits that energy

efficiency and renewables projects

provide, many of which could be

developed in less than three years and

incorporated into a SIP. Examples of

efficiency/renewables projects that have

been accomplished within a 3-year time

frame and have resulted in significant

NOX reductions include reducing boiler

fuel use by utilizing waste heat,

implementing short-term steam trap

maintenance and inspection programs,

and undertaking building upgrades

using EPA’s Energy Star Buildings

approach.

2. Relationship to SIP Submittal Date

Under this rule, as explained in

Section B. below, States are required to

submit revised SIPs by September 30,

1999. Commenters have suggested that

based on the requirements of this

rulemaking, sources in these States

would need to begin early planning of

compliance strategies before the

September 30, 1999 date. The EPA

disagrees. The EPA’s technical analysis

described above indicates that if these

sources begin planning and

specification of controls by even as late

as April 2000, then they would be able

to complete control technology

implementation by May 1, 2003.

3. Rationale

To assure adequate lead-time for

implementation of controls, the EPA has

moved the compliance deadline from

the proposed date of September 2002 in

the NPR to May 1, 2003. Since the ozone

seasons in areas in the eastern U.S. end

in the fall and begin in the spring,

setting the implementation date for May

1, 2003 will provide sources 7–8

additional months for implementing

control requirements while not

undermining the ability of areas to

attain. The additional implementation

time will occur during the cooler

months of the year, a time when ozone

exceedances generally do not occur.

Thus, with either the September 2002

implementation date or the May 1, 2003

implementation date, the 2003 ozone

season would be the first to benefit from

full implementation of the SIP call

reductions.

Several commenters contend that EPA

does not have the authority to establish

the compliance date. Since section

110(a)(2)(D)(i) is silent as to the

implementation schedule for measures

to prevent significant contribution, the

EPA disagrees that the statute prohibits

the EPA from establishing an

implementation date for control

measures that will achieve the

reductions established by the SIP call.

Thus, the EPA must look to the other

provisions in the CAA, the legislative

history, and the specific facts of today’s

rule to determine whether it is

reasonable for the Agency to set the

implementation date for the control

measures. Furthermore, for the reasons

provided in this Section, the EPA

believes it is necessary to use its general

rulemaking authority under section

301(a) to establish the latest date for

implementation through a rule in order

to ensure that downwind areas attain

the standard as expeditiously as

practicable and that areas continue to

make progress toward attaining the

NAAQS. See NRDC v. EPA, 22 F.3d

1125, 1146–48 (D.C. Cir. 1994).

With respect to the facts of this

particular situation, this SIP call entails

a complex analysis of the interstate

transport of NOx and ozone and

involves 23 jurisdictions. Although the

States made significant progress through

the OTAG process, they were unable to

reach a final resolution on the emission

reductions necessary or the schedule to

achieve reductions to address upwind

emissions. Thus, it would not be

reasonable for EPA to leave open the

issue of implementation in light of the

need for downwind areas to rely on

these reductions in order to demonstrate

attainment by their attainment dates.

See also the discussion in Section II.A.

Furthermore, EPA believes that

requiring implementation of the SIPrequired upwind controls, and thereby

mandating those upwind reductions, by

no later than May 1, 2003, is consistent

with the purpose and structure of title

I of the CAA. Under both section

172(a)(2), which establishes attainment

dates for areas designated

nonattainment for the 8-hour standard,

and section 181(a), which establishes

attainment dates for nonattainment

areas for the 1-hour standard, areas are

required to attain ‘‘as expeditiously as

practicable’’ but no later than the

statutorily-prescribed (for section

181(a)) or EPA-prescribed (for section

172(a)(2)) attainment dates. The

implementation date of May 1, 2003 fits

with both the more general requirement

for areas to attain ‘‘as expeditiously as

practicable’’ and the latest attainment

dates that apply for purposes of the 1-

hour standard and that EPA will

establish for the 8-hour standard.

The overarching requirement for

attainment is that areas attain ‘‘as

expeditiously as practicable.’’ This

requirement was established in the CAA

in the 1970 Amendments and has been

carried through in both the 1977 and

1990 Amendments. Thus, although

Congress has provided outside

attainment dates under the 1970, 1977,

and 1990 Amendments, States have

always been required to attain as

expeditiously as practicable. Congress

has furthered this concept of ensuring

that emission reductions are achieved

on an expeditious, yet practicable,

schedule through its inclusion of other

provisions in the CAA that rely on

similar concepts. Most notably, under

both subpart 1 and subpart 2 of part D

of title I of the CAA, areas are required

to make reasonable further progress

toward attainment and thus are not

allowed to delay implementation of all

measures until the attainment year.63

While the ROP requirements directly

apply only to emission reductions that

designated nonattainment areas need to

achieve to address local violations of the

standard, these provisions highlight

congressional intent that—at a

minimum—reasonably available or

practicable measures should not be

delayed if such measures are needed to

attain the standard by the applicable

attainment date. Thus, it is consistent

for EPA to require upwind areas to

adopt practicable control measures on a

schedule that will help to ensure timely

attainment of the standard in downwind

areas.

In addition, the May 1, 2003

implementation date is consistent with

the statutorily-prescribed ‘‘outside’’ 1-

hour attainment dates for many of the

areas that will benefit from the SIP call

reductions.

Currently, areas designated

nonattainment for the 1-hour standard

have attainment dates ranging from

1996 to 2010. For those with attainment

dates in the years 1996–1999, EPA is

analyzing whether such areas should

receive an attainment date extension

due to transported emissions or whether

such areas should be reclassified, or

‘‘bumped up,’’ under section 181(b)(2),

to the next higher classification and

therefore be subject to additional control

requirements and a later attainment
57450 Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations

64See Guidance on Extension of Attainment Dates

for Downwind Transport Areas, Memorandum from

Richard Wilson, dated July 17, 1998.

65Severe-15 areas, such as Baltimore and

Philadelphia, as well as any Serious areas that do

not receive an attainment date extension and are

bumped up due to a failure to attain, will need to

attain no later than 2005.

66Severe-17 areas, such as New York City,

Philadelphia, Chicago and Milwaukee, need to

attain the standard no later than 2007.

67 ‘‘Proposed Implementation Guidance for the

Revised Ozone and Particulate Matter (PM)

National Ambient Air Quality Standards (NAAQS)

and the Regional Haze Program,’’ John S. Seitz,

Director, Office of Air Quality Planning and

Standards, to Regional Office Air Division

Directors, August 18, 1998. The guidance has been

made available for 30-days public comment through

a Federal Register Notice of Availability (63 FR

45060, August 24, 1998). The date of the notice is

the official start date for the comment period.

68 In the NPR, EPA proposed the SIP submittal

date to be within 12 months of the date of final

promulgation of this rulemaking. Promulgation

means signature so long as the rulemaking is made

available to the public on the same day.

date.64 To the extent that an attainment

date extension is appropriate, consistent

with the general requirement of the

CAA, it should be no later than the date

by which the necessary reductions can

practicably be achieved. Thus, it is

appropriate for EPA to require upwind

reductions by May 1, 2003—a date that

EPA has determined can be practicably

achieved—in order to allow these areas

to attain as expeditiously as practicable.

Additionally, there are areas with

attainment dates of 2005 65 and 2007 66

that will benefit from the reductions

upwind States will require in response

to the SIP call. The May 1, 2003

compliance date is sensible in light of

the requirement for these areas to make

reasonable further progress toward

attainment under section 182(c)(2)(B)

and to attain as expeditiously as

practicable but no later than 2005 or

2007.

The implementation date of May 1,

2003 is also consistent with the

attainment date scheme for the 8-hour

ozone NAAQS. The EPA is required to

promulgate designations for areas under

the 8-hour ozone NAAQS by July 2000.

Pub. L. No. 105–178 section 6103 and

CAA section 107(d)(1). In draft guidance

EPA made available for comment in

August 1998, the EPA indicated that

most new areas that violate the 8-hour

ozone NAAQS (but not the 1-hour ozone

NAAQS) can achieve sufficient

emissions reductions to produce one

ozone season’s clean air quality by the

end of 2003 if EPA establishes May 1,

2003 as the compliance date for this

rule.67 The EPA suggested that these

areas would also be eligible for an ozone

transitional classification, provided they

submit a SIP by 2000 (see the August

1998 proposed guidance). Therefore, in

the proposed guidance, EPA has

indicated that when the Agency reviews

and approves ozone transitional area

SIPs, the Agency anticipates

establishing December 31, 2003 as the

attainment date, for planning purposes,

for almost all of the transitional areas.

The EPA believes that establishing

December 31, 2003 as the attainment

date for these areas is consistent with

the requirement of CAA section

172(a)(2)(A) that ‘‘the attainment date

for an area designated nonattainment

with respect to a [NAAQS] shall be the

date by which attainment can be

achieved as expeditiously as

practicable, but no later than 5 years

from the date of designation.’’ The EPA

interprets this requirement to mandate

that controls, either in the downwind

nonattainment area or in upwind areas,

should be implemented as expeditiously

as practicable, when doing so would

accelerate the date of attainment. For

the reasons described elsewhere, the

EPA believes it is practicable for States

to implement the controls mandated

under today’s rulemaking by May 1,

2003, and that doing so would ensure

that areas subject to the 8-hour NAAQS

will attain the standard as expeditiously

as practicable. Doing so will be

consistent with the requirement that

downwind nonattainment areas make

reasonable further progress toward

attainment.

B. Budget Achievement Date

In the NPR, the EPA stated that

although it would mandate the full

implementation of the required SIP

controls by an earlier date, it would

require the affected States to

demonstrate that they will achieve their

NOX budgets as of the year 2007. The

NPR explained that the 2007 date would

allow EPA to make use of the

substantial technical information

collected by OTAG. The OTAG had

selected the year 2007, had collected

inventory data geared towards this date,

and had generated air quality modeling

information geared towards this date.

The NPR further stated that the EPA had

doubts that there would be significant

differences in amounts of emissions and

impact on ambient air quality between

an earlier date and 2007, in light of the

fact that during this period, emissions

would generally increase somewhat as a

result of growth in activities that

generate emissions, but would also

decrease due to continued application

of federally mandated controls.

The EPA continues to believe that

2007 is an appropriate target date for the

affected States to use in demonstrating

whether their SIP will achieve the

required emissions reductions, generally

for the same reasons as expressed in the

NPR. Based on the 2007 projections,

States are expected to achieve their

statewide emissions budgets (based on

the required emissions reductions

achieved by May 1, 2003) by September

30, 2007 which is the end of the ozone

season.

Throughout this rulemaking process,

the EPA has relied on technical data

generated by OTAG geared towards the

2007 date, and it would be an illadvised use of resources if EPA did not

incorporate the emissions inventories

and modeling results generated by the

multi-stakeholder OTAG process, and

instead developed comparable

information for an earlier date. Such an

effort would be time consuming and

resource intensive. Furthermore, no

State is disadvantaged by the

requirement to demonstrate compliance

with the budget later than the

requirement to implement SIP controls

because States may count both the

growth in emissions and the reductions

in emissions from Federal measures that

would occur in the interim. Finally, the

year 2007 is the latest attainment date

under the 1-hour NAAQS for areas in

States affected by today’s rulemaking,

i.e., the severe-17 areas of including

Chicago, Milwaukee, and New York, so

that this date is a sensible target date for

affected States to use in projecting

whether they will achieve the required

emissions reductions.

VI. SIP Criteria and Emissions

Reporting Requirements

A. SIP Criteria

The NPR and SNPR discussed SIP

revision approval criteria and the

schedule for States’ submission plans

for meeting statewide emission budgets

in response to this SIP call under

section 110(a)(2)(D). The EPA received a

number of comments related to the

proposed SIP approval criteria. This

section summarizes these comments on

key issues and presents EPA responses.

1. Schedule for SIP Revision

In the NPR, EPA proposed that each

State must submit a demonstration that

it will meet its assigned Statewide

emission budget (including adopted

rules needed to meet the emission

budget) by September 30, 1999.68 The

EPA received numerous comments

concerning this proposed timeframe.

Comments: The EPA received many

comments on the practicality of

allowing States 12 months to submit

SIPs in response to this rulemaking.

Some commenters articulated that some

States anticipate administrative

obstacles that could create problems in
Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations 57451

submitting their SIP revisions by 1999.

On the other hand, many commenters

expressed concern about extending the

SIP submittal deadline to 18 months

based on the additional adverse impact

that NOX emissions from upwind areas

would have on downwind air quality if

the schedule for reductions were

extended. Arguing that the States would

have ample time to formulate an

approvable SIP, these commenters

supported a 12-month SIP submission

date.

Response: After considering these

comments, EPA is requiring that SIP

revisions be submitted within 12

months after the date of signature of this

final rule. This date is appropriate in

light of the fact that States which are

subject to today’s rulemaking will need

to achieve reductions in NOX emissions

by May 1, 2003. Requiring States to

submit SIP revisions within the 12-

month timeframe will ensure that

controls necessary to reduce these

emissions will be in place on time.

The Agency believes the health risks

associated with ozone pollution require

the NOX SIP call to proceed

expeditiously. Delaying the SIP

submission date by an additional 6

months would hinder downwind areas’

efforts to improve air quality in a timely

manner.

Twelve months is adequate time to

submit a NOX reduction SIP. States were

involved in the OTAG for 2 years and,

during that time, developed lists of

feasible NOX control strategies and

compiled information about control

strategy costs. This groundwork will

assist States in making decisions about

their NOX reduction strategies and

should expedite the SIP submittal

process. Further, States developed NOX

emission inventories for modeling

purposes during the OTAG process. The

States, therefore, have the information

for the source categories on which to

focus. As a result, many elements

needed for putting together a NOX

reduction strategy have already moved

forward.

Since OTAG concluded in June 1997,

the States have had time for internal

review of data, and refinement of their

emission inventories. This SIP call

rulemaking provides EPA’s view of a

reasonable cost-effective strategy to

reduce NOX in the 23 jurisdictions. The

EPA’s action provides a good starting

point for State NOX reduction strategies;

States can embrace the Agency’s

approach or use it as a basis for tailoring

their own programs. If States elect to

participate in EPA’s model trading rule,

the SIP process will be further

simplified because States can adopt the

entire package of recommended

strategies.

Therefore, under section 110(k)(5) for

the 1-hour NAAQS and section 110(a)(1)

for the 8-hour NAAQS, a demonstration

that each State will meet the assigned

Statewide emission budget (including

adopted rules needed to meet the

emission budget) must be submitted to

EPA in its SIP revision.

2. Approvability Criteria

In the NPR, EPA described the

elements listed below that States must

include in their ozone transport SIP

revisions (62 FR 60365).

The EPA proposed that the

approvability criteria for transport SIP

submissions appear in 40 CFR 51.121.

Most of the criteria are substantially

identical to those that already apply to

attainment SIPs, for example, a

description of control measures that the

State intends to use.

The SNPR proposed additional SIP

approvability criteria for control

strategies that will help States meet

their NOX budgets (63 FR 25912–25914).

The legal authority for these additional

approvability criteria was articulated in

the SNPR (63 FR 25913, footnote 5). The

EPA received numerous comments

related to these additional criteria.

a. Source Categories Subject to

Additional Approvability Criteria. In the

SNPR, EPA proposed that, if a State

should choose to meet this SIP call by

regulating NOX sources (boilers,

turbines and combined cycle units)

serving electric generators with a

nameplate capacity greater than 25

MWe and boilers with a maximum

design heat input greater than 250

mmBtu/hr, the State would need to

frame these control measures and

monitoring requirements as either: (1)

Mass emissions limits, (2) emissions

rates assuming maximum utilization, or

(3) an alternative approach, as described

more fully in the next subsection. The

EPA solicited comment on the

reasonableness of extending these

approvability criteria to additional NOX

sources. The EPA explained that the

ability to comply with a mass emissions

limit using reasonably available

technology and to accurately and

consistently monitor mass emissions

were key factors for coverage by the

additional approval criteria.

In the SNPR (63 FR 25923), EPA also

outlined criteria for sources to

participate in the NOX Budget Trading

Program. The EPA explained that the

ability to accurately and consistently

monitor NOX mass emissions was a key

factor for participation in the trading

program. The EPA proposed that the

trading program include the same

sources listed above as well as other

large steam-producing units (units

above 250 mmBtu/hr) which would

include combustion turbines or

combined cycle systems, as well as

boilers that do not serve electrical

generators.

The EPA now believes that the SIP

approvability criteria should cover all

NOX sources serving electric generators

with a nameplate capacity greater than

25 Mwe and all boilers, combustion

turbines and combined cycle units with

a maximum design heat input greater

than 250 mmBtu/hr. The Agency

believes this group is appropriate

because of the considerations set forth

in the SNPR. For example, all of these

sources can comply with a mass

emissions limit using reasonably

available technology and can accurately

and consistently monitor mass

emissions. In addition, EPA believes

that mass emissions limits remain

highly cost-effective for these sources,

even when future growth is

accommodated within the limits. Based

on the analyses in the RIA, EPA projects

that even if actual growth for this group

of sources exceeds EPA’s projected

growth by over one-third, mass emission

limits would remain highly costeffective according to the criteria used

for this rule. Therefore, in this final rule,

EPA is requiring that the additional SIP

approvability criteria outlined below

apply to States that select regulatory

requirements covering boilers, turbines

and combined cycle units that are

greater than 250 mmBtu/hr—regardless

of whether they are connected to an

electrical generator of any size—or to

boilers, turbines and combined cycle

units that serve electrical generators

greater than 25 Mwe, regardless of the

heat input capacity of the unit.

b. Pollution Abatement Requirements.

The EPA proposed requiring States that

choose to meet their budget through

control requirements for such large NOX

sources to express the requirements in

one of three ways: (1) In terms of mass

emissions, which would limit total

emissions from a source or group of

sources; (2) in terms of emissions rates

that when multiplied by the affected

source’s maximum operating capacity

would meet the tonnage component of

the emissions budget for this source or

for these sources; or (3) an alternative

approach for expressing regulatory

requirements, provided the State

demonstrates to EPA that its alternative

provides assurance equivalent to or

greater than option (1) or (2) that

seasonal emissions budgets will be

attained and maintained.

Comments: Seven commenters

generally support the approach of
57452 Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations

expressing regulatory requirements as

mass emissions limitations. One of these

commenters does not object to a mass

limit provided that the limit covers a

time period no shorter than the ozone

season, and that sources should be

allowed to maintain flexibility within

the ozone season. Several commenters

generally support a rate-based limit, one

of which noted that EPA’s own ruleeffectiveness studies show that ratebased limits can be very effective.

Another commenter opposes the use of

mass emission limits and urges EPA not

to require monitoring procedures and

data generation that are inconsistent

with current requirements under the

Acid Rain Program (namely the use of

an emissions rate limit). Other

commenters believe that States, not

EPA, should decide the form of the

limit. Finally, one commenter

recommends both a cap on mass

emissions and an emissions rate

limitation.

Response: As explained in the SNPR

(63 FR 25912), EPA believes that

regulatory requirements in the form of a

maximum level of mass emissions for a

source or group of sources have the

greatest likelihood of achieving and

maintaining the Statewide NOX

emissions budget. As with the entire SIP

call, the new approvability criteria are

designed to apply to total emissions

throughout the ozone season and are not

intended to apply to shorter time

periods within the ozone season. This,

however, does not limit a State’s ability

to require emissions limitations for a

shorter time period if deemed necessary

in a specific ozone attainment plan.

Although several commenters

supported using rate-based limits, they

did not provide evidence to refute EPA’s

belief that the proposed criteria would

provide superior environmental results

over rate-based limits alone. The EPA

maintains that the proposed criteria

provide the greatest assurance to

downwind States that the air emissions

from upwind States will be effectively

managed over time. Regarding EPA’s

rule effectiveness studies, they do

confirm that rate-based limits can be

effective in achieving a specific

emissions rate. However, the studies do

not address the emissions variations

that may take place at the regulated

sources due to changes in utilization

under rate-based limits, including the

potential for significant increases,

particularly in light of utility

restructuring. Under the proposed

criteria, mass emissions from the

regulated sources would stay within a

fixed tonnage amount despite shifts in

utilization of the sources. Finally, EPA

does not believe that the rate-based NOX

emissions limits prescribed under title

IV of the CAA are relevant to this

rulemaking. Since the time of the 1990

CAA amendments, EPA, States, local

governments, and the regulated

community have all gained considerable

experience with regulatory requirements

expressed in terms of mass emissions

limitations which demonstrates their

feasibility and high degree of

effectiveness. For these reasons and the

reasons described in the SNPR, EPA is

including these additional SIP

approvability criteria in today’s action.

c. Monitoring Requirements. The

Agency proposed requiring these large

combustion NOX sources to use

continuous emissions monitoring

systems (CEMS), and requested

comment on requiring the use of the

NOX mass monitoring provisions in 40

CFR part 75 to demonstrate compliance

with applicable emissions control

requirements.

Comments: Some commenters

generally support the use of CEMS for

large combustion sources. One

commenter noted that while the

preamble and the proposed revisions to

part 51 would require CEMS on all

sources, the requirements set forth in

subpart H of part 75 allow for nonCEMS monitoring options for units that

are infrequently operated or that have

low mass emissions of NOX.

Response: The EPA believes that

programs like the Acid Rain Program

and RECLAIM have shown that CEMS

can be effectively used on boilers,

turbines and combined cycle units to

demonstrate compliance with a mass

emissions limitation. The Agency also

believes that, while CEMS provide more

consistent and accurate data, allowing

non-CEMS monitoring options for lowemitting or infrequently operated units

greatly increases the cost effectiveness

of these requirements without

significantly jeopardizing the quality of

the data used to ensure compliance with

the requirements of the SIP call.

Therefore, EPA agrees with the

commenter that the part 75 provisions

allowing non-CEMS monitoring options

for low-emitting or infrequently

operated units are reasonable. The EPA

is requiring the use of the NOX mass

monitoring provisions in 40 CFR part 75

in the final SIP approval criteria.

d. Approvability of Trading Program.

In the SNPR, EPA expressed its intent

to approve the portion of any State’s SIP

submission that adopts the model rule,

provided: (1) The State has the legal

authority to adopt the model rule and

implement its responsibilities under the

model rule, and (2) the SIP submission

accurately reflects the NOX emissions

reductions to be expected from the

State’s adoption of the model rule (63

FR 25913). The EPA also stated that a

State could develop State regulations in

accordance with the model rule. In

Section VII.C.3 of this preamble, the

Agency clarifies the extent to which a

State’s regulations may deviate from the

model rule and still receive streamlined

approval. Regulations providing for

streamlined approval appear in

paragraph (p) of 40 CFR 51.121.

3. Sanctions

In the preamble to the proposed rule,

EPA explained the mandatory sanctions

process that is established in section

179(a) and (b) of the CAA (62 FR 60368).

This process is triggered upon a finding

by EPA that a State failed to submit a

SIP in response to a SIP call. One

sanction—either increased offsets for

new or modified major stationary

sources or restrictions on highway

funding—is imposed 18 months after

the finding is made and the second

sanction 6 months later. The EPA

requested comment on the order in

which these two sanctions should be

imposed in response to the SIP call. The

EPA further requested comment on

whether EPA should use its discretion

under section 110(m) to expand the

geographic scope of the highway

funding sanction.

Comment: One commenter

specifically commented on the order in

which the two sanctions should be

imposed. The commenter recommended

that the offset sanctions apply first—18

months after the finding—and the

restrictions on highway funding apply

second—6 months after the offset

sanction.

Response: This is the approach that

EPA took in its final rule addressing the

sequence of mandatory sanctions for

State failures to respond to submittals

required under part D of title I of the

CAA. For the reasons stated in the

preamble to that final rule (59 FR

39832), EPA is providing in the final SIP

call rule that the offset sanction will

apply 18 months after EPA makes a

finding and the restrictions on highway

funding will apply 6 months after the

offset sanction applies.

Comments: Several commenters

generally commented that EPA should

be fair and equitable in making findings

and imposing sanctions. Other

commenters suggested that to be fair

and equitable—and because the

sanctions are an important backstop to

ensuring emission reduction are

achieved—EPA should apply the same

or similar sanctions to upwind

attainment areas as to nonattainment

areas that do not comply with the SIP

call. Recognizing that the highway
Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations 57453

sanction can apply to attainment areas

only under section 110(m), one

commenter encouraged EPA to develop

a mandatory clock for the imposition of

discretionary sanctions. Finally, one

commenter stated that the nature and

timing of sanctions should reflect a

State’s particular circumstances;

however, this commenter also

emphasized the need for parties to know

the impact of sanctions ahead of time so

that they can effectively react.

Response: The EPA agrees that

sanctions are an important backstop and

plans to make timely findings where

States fail to submit or submit an

incomplete or disapprovable SIP in

response to the SIP call. The EPA agrees

that areas should be treated fairly and

plans to ensure that areas with similar

circumstances are not treated differently

in making findings of failure to submit

and incompleteness. However, at this

time, EPA is not prepared to determine

whether and when it is appropriate to

use the discretion provided under

section 110(m) in imposing sanctions.

The EPA believes it is not appropriate

to make a general determination

regarding the application of sanctions

under section 110(m); rather if

circumstances warrant the use of

sanctions under section 110(m), EPA

may take future rulemaking action to

use that authority. Before EPA uses the

section 110(m) authority, EPA must go

through notice-and-comment

rulemaking, which should provide

States adequate certainty about EPA’s

intentions on the use of discretionary

sanctions and time to respond to any

action that EPA may take.

Comment: One commenter suggested

that the timeframes for the imposition of

sanctions are too short and will

undermine States’ efforts to comply

with the SIP call. In addition, the

commenter states that the imposition of

sanctions serves no useful purpose in

light of EPA’s intent to promulgate a

FIP.

Response: The EPA did not propose

imposing sanctions more expeditiously

than the timeframes mandated by the

CAA. If EPA makes a finding of failure

to submit or incompleteness shortly

after the SIP is due, the State will have

18 months in which to make a

submission that EPA determines is

complete before the first sanction would

be imposed. Thus, the statute provides

sufficient additional time for the State to

correct the problem before any sanction

would apply. Under the statute,

sanctions apply independently of EPA’s

obligation to promulgate a FIP. Congress

recognized that the most efficient and

effective programs are those operated by

the State; thus, the CAA provides for the

continued imposition of sanctions as a

means to encourage States to adopt a

program to replace the FIP.

Comment: One commenter opposes

restrictions on highway funding

imposed by any highway sanction in

nonattainment areas and especially

Statewide.

Response: Under section 179(a) and

(b), the highway funding sanction is one

of two sanctions that must be imposed

due to a continuing failure of a State to

adopt a SIP program, including a SIP in

response to a SIP call. Under section

179(b), the highway funding sanction

can only apply in a nonattainment area.

However, under the discretionary

sanctions provision in section 110(m),

EPA may impose the highway funding

Statewide. (See 59 FR 1476, 1479–80 for

a more detailed discussion.) The EPA

would undertake notice-and-comment

rulemaking before imposing sanctions

beyond the nonattainment area pursuant

to section 110(m).

Comments: Finally, several

commenters recommended that EPA not

sanction serious areas for failing to

demonstrate attainment by 1999 where

those areas are affected by transported

emissions that will not be controlled

until after the 1999 attainment date.

Response: The EPA is not addressing

in this rulemaking the process for

imposing sanctions for areas that fail to

submit or submit incomplete or

unapprovable attainment

demonstrations. The EPA recently

issued a policy memorandum

explaining how it anticipates addressing

transport for serious areas through

rulemaking actions on submitted

attainment demonstrations. See

memorandum from Richard D. Wilson,

EPA Acting Assistant Administrator, to

EPA Regional Administrators, dated

July 16, 1998, ‘‘Extension of Attainment

Dates for Downwind Transport Areas.’’

In the preamble to the proposed rule,

EPA indicated that if an area fails to

implement an approved SIP, the Agency

can make a finding that triggers the

sanctions clock but does not trigger an

obligation to promulgate a FIP. Compare

sections 179(a)(1) and 110(c)(1). One

commenter noted that EPA should take

a forceful role in assuring

implementation. Implementation of

control measures to achieve the

reductions required under the NOX SIP

call is crucial in moving all areas to

attainment of the ozone standards. The

EPA intends to make findings of failure

to implement where the circumstances

warrant such a finding.

4. FIPs

Comment: The EPA received several

comments supporting the approach

outlined in the NPR in which EPA

would propose a FIP at the same time

as taking final action on the SIP call.

The comments noted that the FIPs may

be necessary to enforce the SIP call

budgets and to assure fair treatment of

complying States and industry as

compared to States that are not

responsive to the SIP call. In addition,

many comments were submitted urging

EPA to delay proposal of FIPs until (1)

after the States have had time to

respond to the SIP call, (2) the need for

the FIP is established, or (3) up to 2

years after the final SIP call.

Response: Also signed today is a

separate notice titled ‘‘Federal

Implementation Plans to Reduce the

Regional Transport of Ozone,’’ EPA is

proposing FIPs for each of the

jurisdictions affected by the final SIP

call rulemaking. While EPA will have a

non-discretionary duty to promulgate a

FIP within 2 years of a finding that a

State has failed to submit a complete

SIP, EPA agrees with certain

commenters that the timing of the FIP

proposal should allow for promulgation

in time to require NOX emissions

reductions by sources at about the same

time in States that comply with the SIP

call and States that do not. Under a

delayed FIP proposal approach, sources

in the non-complying States might

experience an unfair competitive

advantage over sources in States which

elected to reduce their NOX emissions

and reduce interstate transport of ozone

and ozone precursors in an earlier

timeframe, consistent with the SIP call

rulemaking. More importantly, delaying

the FIP proposal would potentially

delay reductions of ozone pollution and

NOX emissions in any non-complying

State which would unnecessarily

jeopardize attainment and public health

and welfare. Therefore, proposing a FIP

today will ensure that EPA can

promulgate a FIP very shortly after the

time the SIPs are due, in the event of

any State’s failure to comply with

today’s final rule.

B. Emissions Reporting Requirements

for States

As stated in the November 7, 1997

NPR and the May 11, 1998 SNPR, the

EPA believes it is essential that

compliance with the regional control

strategy be verified. Tracking emissions

is the principal mechanism to ensure

compliance with the SIP call and to

assure the downwind affected States
57454 Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations

69Legal authority for the reporting requirements

was articulated in the supplemental notice of

proposed rulemaking (63 FR 25915–6).

and EPA that the ozone transport

problem is being mitigated.69

1. Use of Inventory Data

If tracking and periodic reports

indicate that a State is not implementing

all of its NOX control measures

beginning on May 1, 2003 or is off track

to meet its required reductions by

September 30, 2007, EPA will work

with the State to determine the reasons

for noncompliance and what course of

remedial action is needed. The EPA will

expect the State to submit a plan

showing what steps it will take to

correct the problems. Noncompliance

with the NOX transport SIP call may

lead EPA to make a finding of failure to

implement the SIP and potentially to

implement sanctions, if the State does

not take corrective action within a

specified time period.

The EPA will use 2007 data to assess

how each State’s SIP actually performed

in meeting the statewide NOX emissions

budget.

2. Response to Comments

The EPA proposed reporting

requirements in the May 11, 1998 SNPR.

That proposal elicited several comments

during the public comment period.

Some of these comments resulted in

changes to the final reporting

requirements.

Comment: One commenter asked that

the EPA review the need for triennial

collection of annual (i.e for the full year)

emissions data for uncontrolled sources,

as compared to collection of only ozone

season data for uncontrolled sources.

Response: The EPA has reviewed the

need for reporting of full year emissions

(as opposed to only ozone season

emissions), and has revised the final

rule to remove a requirement that full

year emissions be reported. In the final

rule, only ozone season emissions must

be reported in the annual, triennial and

2007 reports. This NOX SIP call is aimed

at controlling transport of emissions

during the ozone season and reporting

of full year emission for the purposes of

this SIP call is not necessary.

Comment: One commenter said that

EPA should evaluate the reporting

burden to entities other than the 22

States and the District of Columbia.

These entities are likely to include

owners/operators of facilities that will

be required to report emissions data to

States as part of this information

collection. Another commenter said

EPA should address the additional

resource burden on States and facilities

required to report.

Response: Since the emissions

reporting rule does not place

requirements directly on any sources

but only on the 23 jurisdictions which

receive the SIP call, the EPA is under no

legal obligation to evaluate the indirect

burdens on sources that may result from

the promulgation of this rule. However,

based on EPA’s assumed control

strategy, EPA has performed an analysis

of costs which could be incurred by

facilities if States require facilities

analyzed in EPA’s assumed control

strategy to report information to aid

States in complying with the rule. This

cost information includes both capital

costs for monitoring equipment, such as

continuous emission monitors, and

labor costs for testing. These costs are

included in the RIA for this rule which

is located in the docket for the

rulemaking (docket no. A–96–56).

Comment: One commenter is

concerned that the definition of point

and area sources does not coincide with

the definition of smaller point sources

included in the inventory, nor with the

definition of major sources in ozone

nonattainment areas where the

threshold is either 25 or 50 tons per

year. Another commenter stated that the

definition of ‘‘point source’’ should

reach at least down to the 50 ton per

year level, if not lower. This commenter

also said that, for consistency, EPA

should have a single definition of ‘‘point

source’’ for the purpose of this rule.

Response: All sources with NOX

emissions equal to or greater than 100

tons per year will remain point sources.

However, the EPA has revised its

definition of point source for this final

rule’s reporting requirements to allow

States the option of specifying a smaller

threshold than 100 tons/year of NOX for

defining point source. When a State

chooses this option, non-mobile sources

smaller than the State-defined threshold

would be area sources in that State. This

allows States to tailor their definition of

point source to maintain consistency

with their own current requirements.

In the proposal, the EPA specifically

solicited comments on whether the

State reporting time for source

emissions should be shortened to no

later than 6 or 9 months after the end

of the calendar year for which the data

are collected. This would allow

corrective actions, if needed, to be taken

prior to the next ozone season. The EPA

also solicited comments on whether

different reporting schedules should be

established for the different source

categories, so that the data which can be

obtained more readily would be

submitted sooner. The EPA has received

several comments on these topics,

suggesting a variety of reporting times.

Comment: A State recommended that

since the performance of electric

generating facilities is known promptly,

EPA should shorten the reporting time

to no later than 4 to 6 months after the

end of the ozone season for which the

data are collected. The comment did not

specify whether this reporting period ,

which is shorter than the proposed 12

months, would apply only to electric

generating facilities or should apply to

all NOX emitting sources. Another State

said the point source emissions

reporting period can be shortened to 9

months. Other commenters favored a 12

month or more reporting period. Several

commenters did not believe that 12

months after the end of the calendar

year is a reasonable time to submit

reports and suggested periods ranging

from 18 to 24 months. Some

commenters thought the reporting time

for area and mobile sources must be

longer than for point sources; one

commenter thought the reporting time

for all source types should be uniform.

Response: Many of the emissions from

large electric generating facilities would

be reported directly to EPA more

rapidly than 12 months, if States elect

to adopt the model trading program;

however, the EPA continues to believe

that 12 months from the end of the

calendar year for which the data is

collected is a reasonable time to require

a State to report all emissions from all

types of sources. This 12 month period

is supported by the comments which

say that 12 months, or even less in some

situations, is a sufficient reporting time.

The EPA believes that States can report

emissions from area and mobile sources,

as well as stationary sources, within the

12 month period. The uniform 12 month

reporting period for all source types was

chosen to simplify reporting

requirements. However, a State has the

option of collecting emissions from

particular sectors more rapidly if it

wishes. Therefore in the final rule, the

EPA is requiring that States submit the

required annual and triennial emissions

inventory reports no later than 12

months after the end of the calendar

year for which the data are collected.

Because downwind nonattainment areas

will be relying on the upwind NOX

reductions to assist them in reaching

attainment by the required dates, EPA

believes it is important that data be

submitted as soon as practicable to

verify that the necessary emissions

reductions are being achieved. Early

reports will allow States to more quickly

respond to implementation problems

detected by the reports. States should

formally notify the appropriate EPA
Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations 57455

Regional Office when making the

submittals.

3. Final Rule

After taking into account the

comments submitted in response to the

May 11, 1998 proposal, EPA today is

promulgating emission inventory

reporting requirements for States subject

to the NOX SIP call. The regulatory text

appears in 40 CFR 51.122, and the main

emission reporting requirements are

summarized in Table VI–1 below.

TABLE VI–1.—SUMMARY OF NOX REPORTING REQUIREMENTS

If you own or operate and then, your State must report to EPA the

source’s

A point source ................................................... You are not subject to regulations relied on to

achieve the NOX reductions required in this

SIP call 1.

Ozone season2 emissions.

1. triennially 3,5.

2. for 20075.

A point source ................................................... You are subject to regulations relied on to

achieve the NOX reductions required in this

SIP call 1.

Ozone season emissions.

1. annually 4.

2. triennially 5.

3. for 2007 5.

An area source ................................................. You are not subject to regulations relied on to

achieve the NOX reductions required in this

SIP call 1.

Ozone season emissions.

1. triennially.

2. for 2007.

An area source ................................................. You are subject to regulations relied on to

achieve the NOX reductions required in this

SIP call 1.

Ozone season emissions.

1. annually 6.

2. triennially.

3. for 2007.

A mobile source ................................................ You are not subject to regulations relied on to

achieve the NOX reductions required in this

SIP call 1.

Ozone season emissions.

1. triennially.

2. for 2007.

A mobile source ................................................ You are subject to regulations relied on to

achieve the NOX reductions required in this

SIP call 1.

Ozone season emissions.

1. annually 6.

2. triennially.

3. for 2007.

1The EPA considers the State to rely on regulations to achieve the NOX reductions required if those regulations require reductions beyond

those reflected in the base case 2007 inventory. 2Ozone season is May 1 through September 30.

3Triennial reporting (which is every 3 years) starts with emissions occurring in 2002.

4Annual reporting starts with emissions occurring in 2003.

5Triennial and 2007 reports for point sources contain additional data elements not required in the annual reports.

6The data elements in the annual report for area and mobile sources satisfy the reporting requirements for these source categories for the triennial and 2007 reports. However, the triennial reports start with emissions occurring in the year 2002 and the annual reports start with emissions occurring in the year 2003.

4. Data Elements to be Reported

In addition to reporting the NOX

emissions values shown in Table VI–1,

the State must report other critical data

necessary to generate and validate these

values. This includes data used to

identify source categories such as site

name, location and (source

classification code) SCC codes. It also

includes data used to generate the NOX

emissions values such as fuel heat

content and activity level. The specific

data elements required for each source

category are further defined in 40 CFR

51.122.

5. 2007 Report

The EPA is requiring that States

submit to EPA for the year 2007 a

special onetime statewide NOX

emissions inventory from all NOX

sources (point, area, and mobile) within

the State. The data reporting

requirements are identical to the

reporting requirements for the triennial

inventories, and this reporting

requirement is being imposed to allow

evaluation of whether the budget is met

in 2007. This one-time special inventory

is necessary because the ordinary 3-year

reporting cycle does not fall in the year

2007.

States which must submit the 2007

inventory may project incremental

changes in emissions from 2007 to 2008

to allow the 2008 inventory requirement

to be more easily met and to reduce the

burden on States which must submit

full NOX inventories for consecutive

years, i.e., 2007 and 2008.

The EPA received comments saying

that EPA should not require the special

report in 2007 due to increased

resources required but rather should

adjust the schedule of the triennial

reports so that a triennial report year

will fall on 2007. Alternatively, the EPA

could eliminate the 2008 triennial

report. The EPA has considered these

alternatives, but believes that the

schedule which was proposed is

necessary to maintain consistency with
57456 Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations

other EPA reporting requirements and is

not unnecessarily burdensome.

6. Ozone Season Reporting

The EPA is requiring that the States

provide ozone-season (i.e., May 1

through September 30) inventories for

the sources for which the State reports

annual, triennial and 2007 emissions.

The ozone season emissions may be

calculated from annual data by

prorating emissions from the ozone

season by utilization factors that must

be reported and that are further defined

in 40 CFR 51.122. For the triennial and

2007 reports, ozone season emissions

from all NOX source categories within

the State, controlled or uncontrolled,

must be reported. The EPA is requiring

that each State provide its ozone season

calculation method to EPA for approval.

7. Data Reporting Procedures

When submitting a formal NOX

budget emissions report and associated

data, the State should formally notify

the appropriate EPA Regional Office of

its activities. States are required to

report emissions data in an electronic

format to one of the locations given

below. Several options are available for

data reporting. The State may choose to

continue reporting to the EPA

Aerometric Information Retrieval

System (AIRS) using the AIRS facility

subsystem (AFS) format for point

sources. (This option will continue for

point sources for some period of time

after AIRS is reengineered (before 2002),

at which time this choice may be

discontinued or modified.) A second

option is for the State to convert its

emissions data into the Emission

Inventory Improvement Program/

Electronic Data Interchange (EIIP/EDI)

format. This file can then be made

available to any requestor, either using

E-mail, floppy disk, or value added

network, or can be placed on a file

transfer protocol (FTP) site. As a third

option, the State may submit its

emissions data in a proprietary format

based on the EIIP data model. For the

last two options, the terms ‘‘submitting’’

and ‘‘reporting’’ data are defined as

either providing the data in the EIIP/EDI

format or the EIIP based data model

proprietary format to EPA, Office of Air

Quality Planning and Standards,

Emission Factors and Inventory Group,

directly or notifying that group that the

data are available in the specified format

and at a specific electronic location

(e.g., FTP site). A fourth option for

annual reporting (not for third year

reports) is to have sources submit the

data directly to EPA. This option will be

available to any source in a State that is

both participating in an approved

trading program and that has agreed to

submit data in this format. The EPA will

make both the raw data submitted in

this format and summary data available

to any State that chooses this option.

For the latest information on data

reporting procedures, call the EPA Info

Chief help desk at (919) 541–5285 or email to info.chief@epamail.epa.gov.

8. Confidential Data

Emissions data being requested in

today’s action are not considered

confidential by the EPA (See 42 U.S.C.

7414). However, some States may

restrict the release of certain types of

data, such as process throughput data.

Where Federal and State requirements

are inconsistent, the EPA Regional

Office should be consulted for final

reconciliation.

C. Timeline

The reporting requirements fit into

the general time line summarized

below:

September 30, 1999—Deadline for SIP

submissions in response to this SIP call.

2002—The first triennial emissions

inventory report must be submitted

for ozone season emissions for this

year. States must collect emissions

inventory information for all NOX

sources in the State. This report must

be submitted by December 31, 2003

(i.e., 12 months after the end of the

calendar year for which the data are

collected.)

May 1, 2003—The SIP measures

required to achieve the NOX

reductions must be implemented by

this date.

2003—The first annual emissions

inventory report must be submitted

for certain ozone season NOX

emissions for this year. Specifically,

States must collect emissions

information regarding all sources for

which the State is relying on

measures to meet its NOX budget

(‘‘SIP call sources’’). This report is

due December 31, 2004.

2004—The second annual emissions

inventory report must be submitted

for ozone season emissions from SIP

call sources for this year. This report

is due December 31, 2005.

2005—The second triennial report must

be submitted for ozone season

emissions from all NOX sources for

this year. The report is due December

31, 2006.

2006—The third annual report must be

submitted for ozone season emissions

from SIP call sources in the State for

this year. This report is due December

31, 2007.

2007—The special year 2007 emission

inventory report for ozone season

emissions from all NOX sources in the

State must be submitted for this year.

This report is due December 31, 2008.

The EPA will assess whether States

have met their budgets in the year

2007.

2008—The third triennial emissions

inventory report must be submitted

for ozone season emissions for this

year. This report is due December 31,

2009.

Annual and triennial reports must

continue to be submitted in future years

beyond 2008 in order for the EPA to

track compliance with the budget or any

revisions to the budget that may occur

after 2007.

VII. NOX Budget Trading Program

A. General Background

In the November 7, 1997 proposed

rulemaking, EPA offered to develop and

administer a multi-state NOX trading

program to assist States in the

achievement of their budgets. Today’s

notice sets forth a model program on

which States may choose to base their

SIP submittal. The trading program

employs a cap on total emissions in

order to ensure that emissions

reductions under the transport

rulemaking are achieved and

maintained, while providing the cost

effectiveness of a market-based system.

States can voluntarily choose to

participate in the NOX Budget Trading

Program by adopting the final model

rule, which is a fully approvable control

strategy for achieving over 90 percent of

the emissions reductions required under

the transport rulemaking.

B. NOX Budget Trading Program

Rulemaking Overview

Prior to publication of the proposed

NOX Budget Trading Program, EPA held

two public workshops to solicit

comments and suggestions from States

and other stakeholders on a NOX capand-trade program. Over 150 people

participated in each of the workshops.

To facilitate meaningful comments from

these participants, EPA developed

papers on critical issues that were made

available for review prior to each

workshop. These papers discussed

major issues relevant to developing a

NOX Budget Trading Rule, delineated

options and, in some cases, offered

recommendations. The issues associated

with each working paper were

presented at the workshops, followed by

open discussion periods allowing

workshop participants to comment and

discuss each issue. Input from

workshop participants was extremely

helpful in drafting the proposed NOX

Budget Trading Program. In addition to
Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations 57457

input gained from the workshop

process, the NOX Budget Trading

Program builds directly upon the Ozone

Transport Commission’s NOX Budget

Program and recommendations from the

OTAG’s Trading and Incentives

Workgroup. On May 11, 1998, EPA

published the proposed NOX Budget

Trading Program as a part of the

supplemental notice for the proposed

ozone transport rulemaking. The final

NOX Budget Trading Rule published in

today’s notice reflects changes that have

been made in response to comments

received on the May 11, 1998 proposal.

C. General Design of NOX Budget

Trading Program

1. Appropriateness of Trading Program

The EPA proposed that a voluntary

market-based program be established as

one possible means for a State to meet

its NOX emissions reduction obligations

under the NOX SIP call. The vast

majority of commenters, including

States, industry, and environmental

groups, supported a market approach

over traditional ‘‘command and control’’

mechanisms to fulfill reduction

requirements. However, many

commenters argued that the proposed

State budgets, based on the costeffectiveness of an emission limit of

0.15 lb/mmBtu for large combustion

sources, are too stringent to provide

sufficient surplus allowances to support

a market. These commenters argued that

cost and technological constraints

would prevent regulated sources from

over-controlling, thus reducing the pool

of allowances and the cost savings EPA

predicts would accompany trading.

However, several other commenters

stated that the trading program was the

most cost-effective means to reduce

emissions and would in fact generate

sufficient allowances for trading. These

commenters noted that all but the

highest emitting coal-fired units can

achieve this rate, and that many sources

are able to achieve emission limits

significantly below 0.15 lb/mmBtu.

They also argued that, at least in the

early years of the trading program, the

growth factors used to determine the

budgets will lead to a less stringent

emission reduction requirement than

0.15 lb/mmBtu.

The EPA notes that nothing requires

a State to impose a 0.15 lb/mmBtu limit

on its large combustion sources. The

States will select in their SIPs which

sources to regulate and the type of

regulation to impose in order to achieve

their NOX budgets. The EPA believes

that trading for large combustion

sources under a budget based on 0.15

lb/mmBtu is a feasible, highly costeffective means of meeting a State’s

budget. The Agency believes that 0.15

lb/mmBtu can easily be achieved by gas

and oil-fired boilers. In fact, more than

50 percent of gas and oil-fired boilers

already operate at NOX levels below

0.15 lb/mmBtu and should therefore

easily be able to generate excess

allowances if trading is allowed. The

EPA recognizes that for coal-fired

boilers to operate at or below a 0.15 lb/

mmBtu emission limit, selective

catalytic reduction (SCR) will generally

be necessary. Under a trading scenario,

however, if one coal-fired boiler is able

to emit below 0.15 lb/mmBtu by

installing SCR, it can provide excess

allowance to another coal-fired boiler

and obviate the need for that boiler to

install SCR. (For further technical

justification for the feasibility of 0.15 lb/

mmBtu, see Section III.B.2 of this

preamble.) In summary, EPA concludes

that, should a State elect to control large

combustion sources with a budget based

on an emission rate of 0.15 lb/mmBtu,

ample allowances would exist to sustain

a market under the NOX Budget Trading

Program.

Several of the commenters who did

not support the trading program

proposed by EPA were generally wary of

the use of market approaches for

environmental regulation, especially in

the context of ozone attainment

strategies, citing concerns that

emissions in existing nonattainment

areas may increase under such a

program. The EPA, however, believes

that a trading program is an appropriate

mechanism to achieve the NOX

reductions required under the SIP call.

The EPA proposed the trading program

in the SNPR based on recommendations

from OTAG, experience from the Ozone

Transport Commission, and EPA’s

public workshops held in November

and December 1997. This trading

program was designed to mitigate

transport of ozone and its precursors to

facilitate attainment and maintenance of

the ozone NAAQS. Analyses in

conjunction with the SIP call show that

implementation of a trading program

with a uniform control level results in

no significant changes in the location of

emissions reductions than would result

from a non-trading scenario

(‘‘Supplemental Ozone Transport

Rulemaking Regulatory Analysis’’, April

1998, page 2–19). The NOX reductions

required by the SIP call will

significantly lower background levels of

ozone and can be coupled with local

measures to achieve further NOX

reductions, as well as VOC reductions,

where necessary to reach attainment.

States concerned with contribution by

local sources in the trading program are

free to limit emissions from particular

sources by imposing source-specific

emission limits where deemed

necessary.

2. Alternative Market Mechanisms

The SNPR proposed to establish a

model cap-and-trade program for certain

large combustion sources. This

proposed program employs a cap on

total emissions to ensure achievement

and maintenance of the emissions

reductions required under the NOX SIP

call while providing the flexibility and

cost effectiveness of a market-based

system. Several commenters supported

EPA’s recommendation for a cap-andtrade program. Several others

complained that EPA’s focus on a

capped trading program was

inappropriate, citing OTAG’s

recognition that NOX market systems

could also be implemented without an

emissions cap. As a result, these

commenters felt that EPA could not

make a cap a prerequisite to approval of

a State trading program. They suggested

that EPA recognize that a rate-based

program can be part of a viable SIP,

perhaps by outlining parameters of an

acceptable alternative program or

working with OTAG States to develop a

rate-based program that would better

accommodate future growth. Another

issue raised by a few commenters was

that the trading program would either

conflict with or would ignore existing

local or State-based trading programs.

The EPA first reiterates that the model

program is voluntary (63 FR 25918). In

providing a cap-and-trade program as a

streamlined means by which to comply

with the NOX SIP call, EPA does not

preclude implementation of other

solutions. The purpose of the trading

program is to provide a compliance

mechanism that capitalizes on a proven

means of cost effectively meeting a

specific emissions budget that the

Agency will assist States in

administering.

As OTAG concluded, the procedures

for a cap-and-trade program have

already been developed and used

successfully, whereas procedures for

other types of multi-state trading

programs have not been developed and

implemented to the same degree.

Therefore, EPA does not have the same

level of experience or established

protocols to follow in the design and

administration of other types of trading

programs. The OTAG did encourage

development of provisions to

implement other types of trading

programs, and EPA recognizes that these

alternative trading programs may be

appropriate in some circumstances.
57458 Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations

However, EPA recommends a cap-andtrade program for purposes of the NOX

SIP call because, by limiting total NOX

emissions to the level determined to

address the interstate transport problem,

a cap better ensures achievement and

maintenance of the environmental goal

articulated in the NOX SIP call. In

contrast, under a non-cap trading

program, the addition of new sources to

the regulated sector or increased

utilization of existing sources could

increase total emissions above the level

determined to address transport, even

though a NOX rate limit is met.

States, however, have the flexibility to

respond as they see fit to meet their

emissions budgets established under the

NOX SIP call. States are free to pursue

other regulatory mechanisms or include

other types of trading programs in their

SIPs, whether newly created or already

existing, on the condition that they meet

EPA’s SIP approval criteria as

delineated for the NOX SIP call. These

criteria mandate that regulatory

requirements for boilers, turbines and

combined cycle units that are greater

than 250 mmBtu or that serve electrical

generators that are greater than 25 MWe

be expressed in one of three ways: (1)

In terms of mass emissions; (2) in terms

of emissions rates that when multiplied

by the affected sources’ maximum

operating capacity would meet the

tonnage component of the emissions

budget for these sources; or (3) an

alternative approach for expressing

regulatory requirements, provided the

State demonstrates, to EPA’s

satisfaction, that its alternative provides

equivalent or greater assurance than

options (1) or (2) that seasonal

emissions budgets will be attained and

maintained. For further information

regarding SIP approvability criteria, see

Section VI.A.2.b of this preamble.

3. State Adoption of Model Rule

In the SNPR, EPA proposed that

States electing to participate in the NOX

Budget Trading Program could either

adopt the model rule by reference or

develop State regulations in accordance

with the model rule. The few

commenters on this issue were

primarily concerned about lack of

guidance by EPA in this area for State

adoption of the model rule and the

potential for deviation from the model

rule in the State-adopted rules. This

section clarifies EPA’s intent in issuing

a model rule and distinguishes between

sections of the model rule that State

rules must mirror, and those that States

may choose to alter or eliminate while

maintaining a SIP that is approvable for

purposes of joining the NOX Budget

Trading Program.

a. Process for Adoption. One

commenter suggested that rather than

adopting the NOX Budget Trading

Program, it should be sufficient for each

State to include a statement in its SIP

declaring that the State will participate

in the Federal program, along with a

demonstration of the authority for the

State to do so. This would leave the

details in the Federal rule and avoid

differences that could arise through

each State adopting its own rule.

However, EPA does not have the

statutory authority under title I to

promulgate a Federal cap-and-trade

program to achieve a State’s SIP call

budget unless the State fails to respond

adequately to the SIP call. The EPA

understands the commenter’s concern

regarding differences among State rules

to implement the NOX Budget Trading

Program, and intends to ensure

consistency as explained in the

following Section.

The EPA’s intent in issuing a model

rule for the NOX Budget Trading

Program is to provide States with a

model program that serves as an

approvable strategy for achieving more

than 90 percent of the required

reductions under the NOX SIP call.

States choosing to participate in the

program will be responsible for

adopting State regulations to support

the NOX Budget Trading Program, and

submitting those rules as part of the SIP.

As articulated in the proposed

rulemaking (63 FR 25920), there are two

legal alternatives for a State to use in

joining the NOX Budget Trading

Program: incorporate 40 CFR part 96 by

reference into the State’s regulations, or

adopt State regulations that mirror 40

CFR part 96 but for the variations and

omissions described below.

b. Model Rule Variations. The EPA

would like to clarify the variations and

omissions from the model rule that are

acceptable in a State rule, to provide

States flexibility while still ensuring the

environmental results and

administrative feasibility of the

program. More specifically, EPA will

clarify those variations that maintain a

State’s eligibility for the streamlined SIP

approval associated with adoption of

the model rule, those changes that will

require more extensive review by EPA

prior to approval, and those changes

that are not acceptable for incorporation

into the NOX Budget Trading Program.

In order for a SIP revision to be

approved for State participation in the

NOX Budget Trading Program, on a

streamlined basis or otherwise, the State

rule should not deviate from the model

rule except in the areas of applicability,

NOX allowance allocation methodology,

and early reduction credit methodology

(all of which are described briefly in the

following paragraphs and in more detail

in subsequent Sections of today’s

notice). Deviations from the model rule

regarding allocation methodologies and

early reduction credit methodologies as

defined in this Section do not impact a

State’s eligibility for streamlined

approval of its SIP with respect to the

NOX Budget Trading Program. However,

some deviations regarding applicability

will require more extensive EPA review,

as explained below. Changes to program

applicability may render a State’s rule

ineligible for streamlined approval,

though the rule would still be eligible

for approval after a more thorough EPA

review.

State rules that deviate beyond the

applicability, allocation, and early

reduction credit flexibility provided in

the model rule would not be approvable

for inclusion in the NOX Budget Trading

Program. SIPs incorporating a trading

program that is not approved for

inclusion in the broader NOX Budget

Trading Program may still be acceptable

for purposes of achieving some or all of

a State’s obligations under the NOX SIP

call, provided the SIP criteria outlined

in Section VI.A.2.b are met. However,

only States participating in the NOX

Budget Trading Program would be

included in EPA’s tracking systems for

NOX emissions and allowances used to

administer the multi-state trading

program.

For States participating in the NOX

Budget Trading Program, applicability is

one of the three main areas in which the

State may deviate from the model rule.

State rules need to include an

applicability section that at least covers

the core sources defined in the model

rule, but States may allow additional

stationary sources to participate in the

trading program. These sources must be

able to monitor and report emissions in

accordance with the model rule, and

identify an individual responsible for

fulfilling program requirements to be

eligible for inclusion. States have three

options to expand applicability and one

to limit it, as explained in the following

paragraphs.

States may choose to expand

applicability either by: (1) Including

smaller sources in the core source

categories, (2) including additional

source categories, or (3) providing

individual sources the ability to opt in.

Expansion of applicability to smaller

core sources will maintain the State’s

eligibility for streamlined SIP approval

with regard to the NOX Budget Trading

Program. Including additional source

categories beyond the core sources (e.g.,

municipal waste combustors), however,

will require more careful review by EPA
Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations 57459

in some cases to ensure that the trading

program requirements can be met, and

therefore preclude streamlined SIP

approval otherwise associated with

adoption of the model rule. Regarding

individual source opt-ins, States have

the discretion to determine whether or

not to include this provision in their

State rule. The opt-in provision is not a

prerequisite to approval of a SIP

incorporating the NOX Budget Trading

Program. However, if a State does

choose to include provisions for opt-in

sources, these provisions must mirror

those in the model rule. Providing the

provisions do so, the SIP remains

eligible for streamlined EPA approval.

States may also choose to limit

applicability of the trading program by

allowing units with a low federally

enforceable NOX emission limit (e.g. 25

tons per control period) to be exempt

from trading program requirements. A

State may include this exemption

provision as it appears in the model rule

to allow these sources not to participate

in the trading program, or a State may

omit the provision. Neither of these

actions will interfere with streamlined

SIP approval by EPA, provided the

exemption provisions mirror the model

rule if included in the State rule.

In terms of allocations, States must

include an allocation section in their

rule, conform to the timing

requirements for submission of

allocations to EPA that are described in

this preamble, and allocate an amount

of allowances that does not exceed their

State trading program budget. However,

States may allocate NOX allowances to

NOX budget sources according to

whatever methodology they choose. The

EPA has included an optional allocation

methodology in 40 CFR part 96, but

States are free to allocate as they see fit

within the bounds specified above, and

still receive streamlined SIP approval

for purposes of the NOX Budget Trading

Program.

Today’s final rule also includes an

optional methodology in § 96.55(c) that

States may use for issuing early

reduction credits from the State

compliance supplement pools.

However, States may distribute the State

compliance supplement pool to sources

as they wish in accordance with the

requirements set forth in 40 CFR

51.121(e)(3) and still receive

streamlined SIP approval for purposes

of the NOX Budget Trading Program.

In summary, a State is eligible for

streamlined approval of the portion of

their SIP incorporating the NOX Budget

Trading Program if the State adopts all

the provisions of the model rule (e.g.,

banking and monitoring provisions)

with variations incorporated only in the

manner explained in this Section.

Streamlined approval requires that

applicability extends only to the core

sources, or to core sources and smaller

sources within the core source

categories and that the opt-in provision

and the exemption option for sources

with a low federally permitted emission

limit, if included, mirror those in the

model rule. Regarding allocations,

eligibility for streamlined approval

extends to those State rules whose

allocations do not exceed the State

trading program budget and are

determined in accordance with the

timing requirements delineated in the

model rule. A State rule is still eligible

for approval, but not streamlined

approval, if the applicability

determination for the NOX Budget

Trading Program extends beyond the

core sources to additional source

categories, to allow for the additional

review necessary to ensure such an

extension of applicability is

administratively feasible and

environmentally sound. A State rule is

also eligible for streamlined approval if

it includes methodologies for issuing

credit from the State compliance

supplement pool in accordance with the

provisions in 40 CFR 51.121(e)(3).

Differences among States in these areas

will provide flexibility while not

detracting from the operation or

implementation of the multi-state

trading program. Therefore, variations

as explained in this section are

acceptable to EPA with assurance that

State rules will be sufficiently

consistent. In addition, joint

implementation of the program with

EPA will ensure that once these

consistent rules are established, they

will be implemented consistently as

well.

Several commenters expressed

concern that the lack of prohibitions on

State-imposed trading restrictions in

conjunction with the model rule would

lead to variation between States and

cripple the trading program. The EPA

agrees with commenters that additional

restrictions imposed on the trading

program by individual States could

increase economic costs without

providing significant environmental

benefit. Therefore, EPA does not believe

that any restrictions on trading are

necessary, and does not foresee

approving State rules that include

trading restrictions in SIPs

incorporating the NOX Budget Trading

Program. However, to address local air

quality problems, a State participating

in the NOX Budget Trading Program

may establish permit limitations for

specific sources participating in the

trading program. The EPA considers

such a limitation appropriate given local

air quality concerns and does not

consider it a trading restriction, and

therefore the incorporation of such

limitations will not preclude

streamlined SIP approval. These sources

would still participate in the NOX

Budget Trading Program and the

unconstrained market operating in the

program, but could not use allowances

to exceed their permit limitation; the

source would be held to the permitted

limit, regardless of how many

allowances it holds for the purposes of

the trading program. This topic is

discussed in more detail in the next

Section.

4. Unrestricted Trading Market

a. Geographic Issues. For the NOX SIP

call, EPA is basing the State budgets on

the uniform application of reasonable,

cost-effective NOX control measures for

each State determined to contribute

significantly to nonattainment in a

downwind State. The EPA’s analyses

show that the collective reductions

across the region will produce

significant air quality benefits across the

region. The development of and

justification for the State budgets under

the NOX SIP call is described in Section

III, Determination of Budgets. Although

the analyses in today’s final action

demonstrate that the collective

emissions for the NOX SIP call region

significantly contribute to

nonattainment, the location of particular

emissions does impact the effects that

the emissions have on other areas

within the region. Emissions in some

locations may cause greater overall

effects than emissions from other

locations.

In the SNPR, EPA proposed a single

trading program allowing all emissions

to be traded on a one-for-one basis

without restrictions on trading

allowances within the SIP call region.

The EPA also solicited comment on

whether the trading program should

attempt to factor in differential effects of

NOX emissions based on the location of

the emissions. Possible options for

factoring in the differential effects

include defining exchange ratios for

trades between areas based on the

differential effects of emissions between

areas, establishing subregions for

trading, and/or prohibiting certain

trades (63 FR 25902 at 25919).

The Agency received more than fifty

comments on this issue from the

regulated community, States, and

environmental organizations. A number

of commenters did support limiting

trading by establishing smaller

subregions within the SIP call region or
57460 Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations

establishing trading ratios based on the

idea that there are differential effects of

NOX emissions based on the location of

the emissions. However, none of these

commenters included a complete

proposal with a justification or

description for the appropriate

subregional boundaries or trading ratios.

The majority of commenters on this

subject favored unrestricted trading

within areas having a uniform level of

control. Most commenters supporting

unrestricted trading stated that

restrictions would result in fewer costsavings without achieving any

additional environmental benefit and

would increase the administrative

burden of implementing the program.

They expressed concern that discounts

or other adjustments or restrictions

would unnecessarily complicate the

trading program, and therefore reduce

its effectiveness.

Consistent with the proposal, the final

model rule is designed to be a single

jurisdiction trading program allowing

all emissions to be traded on a one-forone basis, without restrictions or

limitations on trading allowances

within the trading area. EPA has used

the IPM to evaluate the emissions and

cost impacts of alternative regulatory

options under the SIP call for the

electric power sector. These analyses

can be found in the RIA. The model has

been used to show the level and

location of emissions if the SIP call were

implemented under a number of

different alternatives including

unrestricted trading and command-andcontrol approaches. The results indicate

that significant shifts in the location of

emissions reductions would not occur

with unrestricted trading compared to

where the reductions would occur

under command-and-control and

intrastate only trading scenarios. Based

upon the IPM results and EPA’s air

quality modeling, EPA has chosen a

region-wide trading program allowing

all emissions to be traded on a one-forone basis without trading restrictions.

EPA’s analyses suggest that the net

effect of all the trades is that the net

emissions will not significantly shift

within the region compared to a

command-and-control scenario. For this

reason, EPA believes that the need for

trading subregions or trading ratios that

differ from one-for-one are

unsubstantiated for the purposes of this

SIP call and the NOX Budget Trading

Program.

Although the location of net

emissions is not expected to

significantly shift as a result of trading,

it is possible that a State may identify

a specific location (e.g., major NOX

source adjacent to or within an urban

center) where NOX reductions would be

particularly beneficial for ozone

mitigation. For these situations, a State

may establish a specific permit

limitation restricting the amount of NOX

that may be emitted from the source.

The source would still be included in

the trading program but it would not be

allowed to emit above the amount

specified in the permit limitation

regardless of the number of NOX

allowances it may hold. The source

would be allowed to trade the

allowances it is unable to use. In this

way, States will be able to tailor specific

attainment strategies within the

framework of the NOX Budget Trading

Program without restricting the trading

options for most sources included in the

program.

b. Episodic Issues. The EPA also

received several comments addressing

the episodic nature of ozone formation

and whether this should be factored into

the design of the trading program.

Commenters noted that under the NOX

SIP call, which is designed to reduce

total NOX emissions from May through

September of each year, it is still

possible that NOX emissions may be

relatively higher during ozone episodes

compared with NOX emissions on other

days between May and September. In

addition, the effect of a unit of

emissions may be higher during ozone

episodes. To address this concern, the

commenters stated that the trading

program should provide incentives or

safeguards to ensure that NOX emissions

reductions are achieved specifically

during ozone episodes. One commenter

asserted that emissions could either be

capped during ozone episodes or that

the trading program could place a

premium on the use of NOX allowances

during ozone episodes. The commenter

recommended the latter option. The

premium would require that sources

surrender NOX allowances at rates

greater than 1-to-1 for each ton of NOX

emitted during the ozone episodes.

Consistent with the NOX SIP call, the

NOX Budget Trading Program focuses

on reducing total NOX emissions from

May to September for the jurisdictions

that are identified in the NOX SIP call

and that choose to participate in the

trading program. Proposals to address

NOX emissions during specific episodes

and in specific nonattainment areas are

more closely tied to issues affecting

individual attainment plans rather than

the goal of the NOX SIP call which is to

reduce transport. It would be very

difficult to apply the appropriate

premium to the individual sources that

contribute NOX emissions affecting

specific ozone episodes. The

meteorology and source contribution for

each ozone episode is different. And in

some cases, NOX emissions and the

resulting ozone may be transported for

several days before contributing to an

ozone violation.

Provisions designed to ensure that

NOX emissions reductions are achieved

specifically during ozone episodes are

more likely to be effective in controlling

NOX emissions that are released

adjacent to or within locations

frequently affected with elevated ozone

levels. Where a State identifies such a

source, EPA believes specific permit

limitations are an appropriate and

effective method for controlling the

source’s emissions. As stated in the

previous section, EPA believes that

States may use permit limitations to

tailor specific attainment strategies

within the framework of the NOX

Budget Trading Program without

restricting the trading options for most

sources included in the program.

Furthermore, this provides each State

more flexibility in establishing its

attainment plan rather than applying

one approach to address the episodic

nature of ozone throughout the SIP call

region. Therefore, EPA has not included

additional trading restrictions to address

ozone episodes in the design of the final

NOX Budget Trading Program.

D. Applicability

1. Core Sources

In the SNPR, EPA proposed that

compliance with the emission limitation

requirements of the NOX Budget

Trading Rule, i.e., the requirement to

hold sufficient NOX allowances to cover

emissions, apply to a core group of large

stationary sources that includes all

fossil fuel-fired stationary boilers,

combustion turbines, and combined

cycle systems (i.e., units) that serve an

electrical generator of capacity greater

than 25 MWe and to any fossil fuel-fired

stationary boilers, combustion turbines,

and combined cycle systems not serving

a generator that have a heat input

capacity greater than 250 mmBtu/hr. A

unit was considered fossil fuel-fired if

fossil fuels accounted for more than 50

percent of the unit’s heat input on an

annual basis. The EPA solicited

comment on the appropriateness of the

categories included in the core group,

whether the size cut-offs should be

higher or lower for the source

categories, and the appropriateness of

including other source categories in the

core group. Comments on the concept of

a core group fell into three broad

categories:

• Those who agreed with the core

group concept and who generally agreed
Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations 57461

with EPA’s proposed core group

definition;

• Those who felt that the core group

definition was too limiting; and

• Those who felt that the core group

definition was too inclusive.

a. Commenters Who Felt the Core

Group Should Not Be Changed.

Commenters who supported the concept

of a core group generally and the cutoffs proposed by EPA specifically

explained that the cut-offs are consistent

with the Acid Rain Program and that the

use of a core group will minimize

inconsistencies that could impede

establishment of interstate trading.

Commenters also added that the

program should provide the flexibility

to allow additional sources to opt-in on

an individual basis or for States to bring

in additional sources on a categorical

basis. Some of these commenters added

that the timing for bringing in these

sources or source categories should be

dependent upon the ability of the source

or source category to accurately monitor

emissions. For some source categories it

might be appropriate to bring them in at

the start of the program; for others, it

might be necessary to wait until their

ability to quantify emissions has

improved.

Commenters who generally supported

the concept of a core group of sources

as it was defined in the SNPR did have

several specific concerns. One

commenter noted that while the SNPR

preamble clearly explained that the rule

only included fossil-fuel-fired units, the

rule itself was not clear on this issue.

Another commenter suggested that

because the proposed definition

differentiated between electrical

generating units and non-electrical

generating units it excluded sources that

should be in the trading program such

as cogeneration facilities that consisted

of boilers greater than 250 mmBtu/hr

that served electric generating units

with a rating of less than 25 MWe.

The EPA agrees that the establishment

of a core group will help facilitate

interstate trading as well as compliance

with the emissions budget. If there is

not some minimum group of trading

participants, sources that are in the

program will have less of an

opportunity to trade allowances and

realize the economic benefits of trading.

In addition, by ensuring that most of the

emissions from industries covered by

the trading program are included in a

capped system, the trading program can

be simplified because concerns about

load shifting to uncapped sources is

minimized. The EPA also agrees that

making the cut-offs consistent with

existing regulatory programs helps to

minimize conflicts with existing

regulatory programs. The EPA also

agrees with both of the concerns raised

by the commenters. Therefore the

regulatory definition of unit has been

clarified to make it clear that a unit

must be fossil-fuel fired. The EPA has

also added a clarification to the

definition of fossil-fuel fired. This

clarification is intended to define a

baseline period for determining if a unit

is fossil-fuel fired. The revised

definition states that fossil-fuel fired

means the combustion of fossil fuel,

alone or in combination with any other

fuel, where the fossil fuel comprises

more than 50 percent of the annual heat

input on a Btu basis. An existing unit is

considered fossil-fuel fired if it meets

this criterion for any year since 1990 (or

if not operating since 1990 during the

last year of operation). A new unit is

considered fossil-fuel fired if it is

projected to meet this criterion or, if

after operation begins, it does meet this

criterion.

In addition, to address the concern

about excluding cogeneration facilities

that are greater than 250 mmBtu/hr that

serve electric generating units with a

rating of less than 25 MWe, the

applicability has been changed to

include all units greater than 250

mmBtu/hr, regardless of how much

electricity they generate.

b. Commenters Who Felt the Core

Group Should Be Expanded.

Commenters who felt the trading

program should be expanded focused on

a number of areas. Several commenters

argued generally that the program

should allow any source to participate

if the source can document that

emissions reductions have been

achieved. A number of commenters

mentioned as examples the inclusion of

medium-sized and smaller stationary

sources in the RECLAIM program. A few

commenters argued that the addition of

certain sources is needed for

consistency with the OTC NOX Budget

Rule. Other commenters opposed the

core group concept because they believe

that regulation of low-level and local

sources in the Northeast is an essential

step in solving the ozone problem.

Others argued that excluding non-utility

sources from the trading program

unfairly excludes these sources from

least-cost compliance options. Some

commenters suggested specific

categories of units that should be

allowed to, but not required to,

participate in the trading program.

These included:

(1) Municipal waste combustors;

(2) Internal combustion engines;

(3) Process units;

(4) Units for which the output product is not

comparable to other units on which the

allocations are based, such as process

heaters, hazardous waste incinerators,

process vents and nitric acid plants.

The EPA believes that many of the

concerns about the core source

definition stem from a

misunderstanding of its purpose. The

core sources definition was intended to

indicate the minimum applicability

requirements that a State rule would

have to include to participate in a larger

multi-state program that EPA would

help to administer. It was not intended

to limit individual States from including

more sources (as long as the sources

meet certain criteria further explained

below) in the larger multi-state program

(63 FR 25924). Nor was it intended to

prohibit a State (or group of States) from

developing its own trading program

with a more limited applicability.

If, however, a State or group of States

developed a trading program that did

not meet the minimum requirements set

forth in the model NOX Budget Trading

Program, such as minimum core source

applicability, EPA would not participate

in the administration of such a trading

program. This is because it would not be

administratively cost-efficient for EPA

to manage multiple trading programs

with a variety of applicability and other

requirements designed to address the

same issue.

The EPA is not expanding the core

source group to include any additional

sources because EPA believes that this

decision is better left to the states.

Therefore the model rule will allow a

State to expand the applicability of the

trading program to include additional

stationary sources if the sources meet

certain criteria. These criteria include

the ability to accurately and consistently

monitor and report emissions and the

ability to identify a party responsible for

ensuring that monitoring and reporting

requirements are met, for authorizing

allowance transfers and for ensuring

compliance. The EPA’s rationale for

setting these minimum criteria are set

forth in the preamble to the SNPR (63

FR 25923). Also, EPA addresses issues

specifically related to the monitoring

requirements for these sources in

Section D.3 of today’s preamble.

There are two mechanisms that can be

used to include more sources in the

program. One is for a State to expand

the applicability criteria to include

other source categories; the other is to

give individual sources the ability to

opt-in.

States that choose to expand the

applicability criteria can do so (1) by

lowering the applicability threshold for

source categories that are already part of
57462 Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations

the core group in order to include

smaller sources or (2) by including

additional source categories that are not

included in the core group. For instance

a State in the OTC might choose to

lower the applicability cut-off for

electrical generating units to 15 MWe to

make the program more consistent with

the existing OTC NOX Budget Program.

If a State chose to expand the

applicability criteria for source

categories already included in the core

group this would not affect EPA’s

streamlined approval of the NOX Budget

Trading program component of the

State’s SIP.

A State might choose to lower the

applicability cut-off for sources in the

core group to create different

applicability cut-offs for new and

existing units. This could help to better

facilitate integration with a State’s new

source review program. The EPA took

comment on this concept in the SNPR

and received comments both for and

against this proposal. Commenters who

opposed it suggested that it would be a

disincentive to replace old units with

new cleaner units. Some of these

commenters also noted that expanding

the applicability cut-off for all units

would provide an incentive to replace

these older units. Commenters who

favored it suggested that it would be an

incentive to make new units as clean as

possible. The EPA believes that it is

appropriate for States to determine how

best to handle the issue of small new

units.

Another reason to allow smaller

sources to opt-in is to simplify

monitoring for situations in which a

common stack is shared by a number of

units, some of which are affected and

some which are not. In this situation the

owner or operator would have to either

install monitors at each of the affected

units, or install monitors at the common

stack and at all of the non-affected units,

so that the emissions from these units

could be deducted from the emissions

from the affected units. If the owner or

operator is allowed to opt-in the

nonaffected unit, they will be able to

install one set of monitors at the

common stack accounting for the

emissions from all of the units.

If a State chose to include additional

source categories, EPA would have to

review the SIP submittal to ensure that

those additional source categories met

the minimum criteria for monitoring

and reporting emissions and for having

a responsible official. As further

explained in the SNPR (63 FR 25924),

EPA would also have to determine if it

could successfully administer a regional

trading program with the inclusion of

these additional source categories.

In the SNPR, EPA proposed

developing a list of specific additional

source categories beyond the core group

which a State could bring into the

trading program without affecting EPA’s

streamlined approval of the trading

component of the SIP. While this

concept received general support, none

of the commenters provided enough

specific support to demonstrate that all

of the sources in a given source category

could meet the criteria to accurately and

consistently monitor emissions. These

comments are discussed in Section D.3.

The EPA believes that the opportunity

for States to expand the applicability to

include additional sources addresses

concerns about incompatibility with the

applicability requirements of existing

programs, such as the OTC Trading

Program, as well as concerns that an

individual State might want to expand

the program to address local ozone

problems.

The other mechanism that can be

used to broaden the applicability of the

program is the individual opt-in

procedures in subpart I of part 96. These

provisions allow a source to opt-in, if it

can meet the monitoring and reporting

requirements of part 75. The EPA

received a number of comments about

the monitoring requirements of part 75

as they related to opt-ins. These

comments are addressed in Section D.3

of today’s preamble.

In the SNPR (62 FR 25940–25942 and

62 FR 25991–25994), EPA proposed that

the individual opt-in provisions would

only be applicable to fossil-fuel-fired,

stationary boilers, combustion turbines,

and combined cycle systems smaller

than the applicability cut-offs of 25

MWe or 250 mmBtu/hr. The EPA agrees

that the RECLAIM program has

demonstrated that many combustion

sources that are not included in the core

applicability criteria can accurately and

consistently monitor NOX mass

emissions using CEM (or other

alternative protocols for units with low

mass emissions) that are very similar to

the provisions in subpart H of part 75.

Therefore, in today’s action EPA is

allowing States to expand the opt-in

provisions to include any stationary

combustion source that emits to a stack

and can meet the monitoring and

reporting requirements of subpart H of

part 75.

States that choose to add other

combustion sources that are not part of

the core group would also have to

address issues related to allocating

allowances for those types of sources.

Allocation methodologies that may be

appropriate for source categories

covered in the core group may not be as

applicable for other source categories.

For instance, as one commenter noted,

an output based allocation methodology

might not make as much sense for a

municipal waste combustor, since the

primary purpose of a municipal waste

combustor is to combust waste, not to

generate usable output.

c. Commenters Who Felt the Core

Group Is Overly Inclusive. A number of

commenters argued that the burdens

associated with including certain source

categories would outweigh the benefits

and that particular types of sources

should therefore be excluded from the

core group. Many of these commenters

stated that individual sources in these

groups should be allowed to opt in

where there is a net economic benefit to

them to participate rather than

mandating inclusion of the source

category. Specific categories include:

non-utility boilers generally; generators

of power for on-site use; combustion

turbines exempt from Title IV; small

cyclone boilers; combustion turbines

below 100 MWe; small, particularly

municipal, electric generating units

(e.g., those under 25 MWe); and units

with low potential to emit as defined by

enforceable limits (e.g., peaking units

with potential to emit less than 100 tons

per year).

The EPA does not believe there is a

great distinction between similarly sized

utility and non-utility boilers. Both

categories of boilers are similar in

design, have similar control options and

have similar control costs. Therefore,

EPA is not excluding large non-utility

boilers from the trading program. The

EPA believes the same arguments that

apply to utility and non-utility boilers

also apply to generators of power for onsite use and generators of power for

resale. In light of the fact that utility

restructuring will provide more

opportunities for generators of power for

on-site use to resell the power they

produce in the future, EPA believes that

this distinction is even harder to make.

Therefore, EPA is not excluding large

generators of power for on-site use from

the trading program.

In accordance with title IV of the

CAA, the Acid Rain Program exempts

simple combustion turbines that

commenced commercial operation

before November 15, 1990. These units

were exempted from the Acid Rain

Program because the SO2 emissions

from these units were extremely low.

The NOX emissions from these units are

potentially higher; therefore, EPA is not

adding a specific exemption for these

types of units. However, many of these

units are small and/or infrequently

operated, so their actual NOX emissions

may be quite low; therefore, some of

these units may qualify for the
Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations 57463

70The lowest emission rate required under part

76 is 0.40 lbs/mmBtu.

alternative compliance options for units

with low NOX mass emissions,

explained below. Combustion turbines

smaller than 100 MWe are also likely

candidates to qualify for the alternative

compliance option explained below.

The Acid Rain Program exempts

cyclone boilers with a maximum

continuous steam flow at 100 percent

load of greater than 1060 thousand lb/

hr from NOX control requirements

under part 76. These units were

exempted because one of the primary

criteria in title IV of the CAA for setting

emissions limitations under part 76 was

comparability of cost with low NOX

emission controls on boilers categorized

as group 1 boilers under Title IV (large

tangentially fired and dry bottom, wall

fired). There is no such criterion in the

CAA applicable to this rulemaking.

Also, since the emission reductions

required by this rulemaking are more

substantial than the emission reductions

required under part 76 70, the cost per

ton of reducing NOX emission

reductions is correspondingly higher.

Therefore, applicability cutoffs that

were relevant in the part 76 rulemaking

are not relevant in this rulemaking.

In response to the comment that small

electrical generators less than 25 MWe

should be exempt from the NOX Budget

Trading Program, they were proposed to

be exempt and will be exempt under the

final model rule. They do still have the

option of opting into the program if they

choose to do so.

In the SNPR (63 FR 25926), EPA took

comment on allowing units with a low

federally enforceable NOX emission

limit (e.g. 25 tons per ozone season),

that because of their size would be

included in the trading program, to be

exempt from the requirements of the

trading program. In general commenters

supported this concept. One commenter

who supported the concept also added

that it would be important to ensure that

there were adequate requirements to

assure that the individual sources who

took advantage of this option

demonstrated compliance with their

unit-specific caps. The commenters who

disagreed with this option expressed

concern that a State’s budget could be

exceeded if emissions from these units

were not accounted for.

Based on the comments received EPA

continues to believe that it is

appropriate to offer States the option of

providing units that are above the

applicability threshold but that have a

very low potential to emit an alternative

compliance option. This option would

allow units that meet the requirements

described below to be exempt from the

requirements to hold allowances, and to

comply with quarterly reporting

requirements. In order to address the

concern that sources must demonstrate

compliance with their individual cap,

EPA has added specific requirements

that sources must meet in order to use

this alternative compliance option.

Units that use this option would be

required to:

(1) have a federally enforceable permit

restricting ozone season emissions to

less than 25 tons;

(2) keep on site records demonstrating

that the conditions of the permit were

met, including restrictions on operating

time;

(3) report hours of operation during

the ozone season to the permitting

authority on an annual basis.

A unit choosing to use this

compliance option would be required to

determine the appropriate restrictions

on its operating time by dividing 25 tons

by the unit’s maximum potential hourly

NOX mass emissions. The unit’s

maximum potential hourly NOX mass

emissions would be determined by

multiplying the highest default emission

rate for any fuel that the unit burned

(using the default emission rates, in part

75.19 of this chapter) by the maximum

rated hourly heat input of the unit (as

defined in part 72 of this chapter).

States would be allowed, but not

required, to incorporate this alternative

compliance option into their SIPs. The

EPA does agree that if a State does

incorporate this option into the SIP, it

would have to account for the emissions

under its budget. Thus a State that chose

to use this option would have to either:

(1) Subtract the total amount of

potential emissions permitted to be

emitted using this approach from the

trading portion of the budget before the

remaining portion of the trading budget

is allocated to the trading participants;

or (2) Offset the difference between total

amount of potential emissions permitted

to be emitted using this approach and

the 2007 base year inventory emissions

for these same sources with additional

reductions outside of the trading portion

of the budget.

If States choose not to incorporate this

alternative compliance option into their

SIPs, or if they choose to incorporate it

exactly as it is set forth in the model

rule, it will not affect the streamlined

approval of the trading rule portion of

the SIP. A State may choose to require

an alternative means of ensuring that

the potential to emit for units utilizing

the alternative means of compliance is

limited to less than 25 tons, however if

a State deviates from the model rule in

this way, the SIP will no longer receive

streamlined approval.

2. Mobile/Area Sources

The proposed rule did not include

mobile or area sources in the trading

program, but solicited comment on

expanding applicability to include these

sources, or to include credits generated

by these sources, in the trading program.

Mobile and area sources were not

included in the proposed trading rule

due to EPA’s concerns related to

ensuring that reductions were real,

developing and implementing

procedures for monitoring emissions,

and identifying responsible parties for

the implementation of the program and

associated emissions reductions.

The EPA received comment from

State and local government, industry

and coalitions of industry, and

environmental groups regarding the

inclusion of mobile and area sources in

the program. Comments focused on the

following main areas: inclusion or

exclusion of mobile and area sources,

subcategories of mobile sources for

inclusion, and the use of pilot programs

to foster innovation.

Some commenters urged EPA to

include mobile and area sources with as

few restrictions as possible in the

trading program, primarily on an opt-in

or voluntary basis. These commenters

argued that excluding mobile sources

would reduce the potential scope and

benefits of the trading by placing a large

portion of States’ NOX inventory outside

the scope of the trading program. They

noted that the existence of RECLAIM

protocols for mobile and area source

credit generation demonstrated that

EPA’s quantification, verification, and

administration concerns were

misplaced.

The majority of commenters,

however, indicated that mobile sources

should not be included at this time and

that the model rule should not be

delayed to address concerns related to

inclusion of these sources. Some

commenters argued against ever

including mobile and area sources in

the program. One State argued that

inclusion of mobile and area sources

would destroy the integrity of the

program since mobile and area source

reductions are not necessarily real,

verifiable and quantifiable, failing to

display a level of certainty comparable

to those sources included in the trading

program. A few commenters indicated

that mobile sources were inherently

unsuited to a capped system, since the

difficulties of measuring emissions from

these sources precludes their inclusion

in a budget.
57464 Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations

Several commenters suggested that

some categories of mobile sources

should be included while other

categories should not. Commenters

indicated, for example, that it is not

feasible to have individual motorists

participate in the cap-and-trade program

due to the burdens and administrative

complexity associated with such a vast

number of sources and responsible

parties in a trading system.

Alternatively, commenters argued that

manufacturers, fuel distributors, and

fleet owners could be included if they

were able to generate surplus emission

reductions by going beyond the

requirements established by some

Federal measures. These commenters

specifically cited the low-RVP

regulations, the vehicle scrappage

guidance, and the locomotive

regulations as examples of such Federal

measures.

Several commenters who

recommended that mobile sources not

be included in the program at this time

also recommended that EPA sponsor

pilot programs in States to study the

feasibility of inter-sector trading and to

develop mechanisms to address the

specific concerns mentioned regarding

the inclusion of mobile and area

sources. Along similar lines, one

industry commenter stated that mobile

sources may be appropriate candidates

for participation in the trading program

only if adequate emission reduction

measurement protocols can be

developed. Foreseeing this occurrence,

some commenters felt that EPA should

leave a placeholder in the rule or add a

provision that would include mobile

and area sources once the mechanisms

to address the specific concerns of EPA

and others have been developed.

The model trading program that EPA

is finalizing today will not include

mobile and area sources for the reasons

outlined in the SNPR. The EPA concurs

with the concerns raised by commenters

against the inclusion of mobile and area

sources, regarding program integrity,

emissions monitoring, and

accountability. Most of the proponents

of including mobile or area sources

listed general reasons for including

them such as increasing market

efficiency, lowering costs, or simply the

existence of RECLAIM protocols to do

so. However, these commenters did not

provide sufficient information or

documentation to support the validity of

these assertions, and several

acknowledged that the potential for

improvement in market efficiency or

lower compliance costs was difficult to

ascertain. Further, one proponent

acknowledged that the RECLAIM

protocols are new and not yet

extensively utilized.

In fact, a recent audit of the RECLAIM

program indicates that the volume of

mobile source credits used under the

program is very small (only 99 NOX tons

have been converted from mobile source

reductions in the last five years). Only

5 requests for conversion of mobile

source emission reduction credits to

RECLAIM trading credits were approved

in 1994, and no further requests had

been received as of May 1998. The small

amount of credits relative to the

significant resource expenditure for the

conversion of mobile source credits

under the RECLAIM program (i.e., the

need for case-by-case review given the

variability and complexity of the

petitions) suggests that the RECLAIM

mobile source protocols and strategy are

not yet a cost-effective option for the

trading program.

The EPA remains willing to consider

adding mobile or area sources to the

trading program in the future. Most

commenters recommended that the

program be opened to mobile or area

sources once adequate mechanisms are

developed for addressing related

concerns. In response to these

comments, and those recommending

that EPA support pilot programs in

States in order to facilitate resolution of

the areas of concern for mobile and area

sources, EPA will investigate how grant

funding may be used for such pilots.

Additionally, EPA is pursuing possible

ways to incorporate mobile and area

source strategies into other trading and

incentive programs. Through these

efforts, EPA will work with States in

finding solutions to adequately address

concerns such as emissions variability,

difficulty in controlling emissions

growth, difficulty in monitoring

emissions levels, and difficulty in

establishing emissions baselines.

Through this process, EPA and States

will explore and develop the necessary

protocols that could eventually allow

the inclusion of mobile and area sources

in some capacity in the NOX Budget

Trading Program. Anticipating that the

quantification, verification, and

administration concerns regarding

expansion of the trading program to

include mobile and area sources may be

sufficiently resolved in the future, EPA

is reserving in this rulemaking a section

in part 96 for future inclusion of mobile

or area sources in the NOX Budget

Trading Program.

The EPA is aware of other concerns

on which the Agency did not receive

comment, including the adequacy of

some of the existing mobile source

protocols and the enforcement of mobile

source credit generation strategies.

These emerging issues, coupled with

past experience, and the issues raised by

commenters lead EPA to conclude that

it is not appropriate to include mobile

and area sources in the NOX Budget

Trading Program at this time.

3. Monitoring

For the reasons set forth in the SNPR

(63 FR 25938–40), EPA proposed that

sources in the NOX Budget Trading

Program use the monitoring

methodologies in proposed subpart H of

part 75 to quantify their NOX mass

emissions (63 FR 28032). The comments

that EPA has received can be classified

into three main categories:

• Support for requiring the use of part

75 to demonstrate compliance with the

trading program,

• Support for using CEMS on large

units, but concerns about using part 75

as the monitoring protocol, and

• Concerns about requiring CEMS.

Some of the commenters concerned

about requiring CEMS focused on units

of any size that are not subject to the

provisions of the Acid Rain Program.

Others focused on smaller units.

The EPA proposed revisions to part

75 (63 FR 28032) for a number of

reasons, one of which was to add

procedures for monitoring NOX mass

emissions (subpart H). These procedures

could be used by sources to comply

with any State or Federal program

requiring measurement and reporting of

NOX mass emissions. In particular,

subpart H would be used by sources to

meet the monitoring and reporting

requirements of the NOX Budget

Trading Rule (part 96) and the

monitoring and reporting requirements

of the SIP call for (1) combustion units

(boilers, turbines and combined cycle

units) which serve electric generators

greater than 25 MWe and (2)

combustion units greater than 250

mmBtu/hr, regardless of whether they

serve a generator.

The part 75 revisions also proposed to

make a number of other changes that

would affect units using part 75 to

comply either with the requirements of

title IV or the requirements of a NOX

mass emissions program that

incorporated or adopted the

requirements of part 75. These included

a number of minor changes to simplify

and streamline the rule to make it more

efficient for both affected facilities and

EPA, a new excepted monitoring

methodology that would reduce

monitoring burdens for affected facility

units with low mass emissions, new

quality assurance requirements based on

gaps identified by EPA during

evaluation of the initial implementation

of part 75, and several minor technical
Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations 57465

changes to maintain uniformity within

part 75 and to clarify various provisions. The following discussion addresses

comments received in the SNPR docket

(A–96–56) that are related to the general

requirement to monitor emissions, the

requirement to monitor emissions using

CEMS, and the requirement to monitor

using part 75. Although EPA had

requested that all comments related to

the use of part 75 for monitoring NOX

mass be submitted to the part 75 docket

(A–97–35), some comments also dealt

with the specific requirements set forth

in part 75. In today’s rulemaking, EPA is

finalizing sections of part 75 related to

monitoring NOX mass emissions as well

as those which address the excepted

monitoring methodology for units with

low mass emissions of NOX and SO2

that combust oil or natural gas. Units

using this methodology to comply with

the requirements of part 96 would be

subject only to the NOX mass emission

requirements and not to the SO2 mass

emission requirements. For a more

complete discussion of the NOX mass

monitoring and reporting provisions in

part 75, see the Amendments to Part 75

Section below and Appendix A of this

preamble. These Sections discuss both

the comments received in the part 75

docket as well as the comments received

in the SNPR docket that address the

specific requirements of part 75. a. Use of Part 75 to Ensure

Compliance with the NOX Budget

Trading Program. Several commenters

supported the idea of requiring all

sources in the trading program to meet

the monitoring provisions of part 75.

Some of these commenters noted that

part 75 provides the consistent and

accurate monitoring requirements

necessary to ensure the integrity of a cap

and trade program. They also noted that

the proposed revisions offered the

flexibility needed for sources to be able

to reasonably comply. Several commenters supported the

concept of trying to consolidate the

monitoring and reporting requirements

for units in the NOX Budget Trading

Program already subject to part 75 under

the Acid Rain Program. Response: The EPA agrees that

accurate and consistent data are

important to ensure the integrity of a

trading program and that the protocols

in part 75 provide for such accurate and

consistent data from stationary

combustion sources. Today’s final

model rule would require all sources in

the trading program (including sources

currently subject to part 75) to use the

monitoring and reporting procedures set

forth in subpart H of part 75. b. Use of CEMS on Large Units. A

number of commenters expressed

support for the requirement that large

units should use CEMS to quantify NOX

mass emissions. Many of these

commenters did, however, have

concerns about using part 75 as the

basis for this monitoring. Some of these

commenters elaborated that part 75 was

specifically developed for utility units

and that it might not be applicable to

other types of units. Commenters also

expressed concerns about costs

associated with upgrading existing CEM

systems to meet the part 75

requirements. The main alternatives

they suggested were either using

existing State monitoring and reporting

requirements or allowing States the

discretion to create or approve new

monitoring and reporting requirements. Response: For reasons set forth in the

preamble to the SNPR, EPA believes

that the use of CEMS, in general, and

the protocols in part 75, more

specifically, are the most effective way

to ensure that NOX mass emissions from

large combustion sources are quantified

in an accurate and consistent manner

from source to source and are reported

in a consistent and cost-efficient way.

This is important to maintain the

integrity and efficiency of the trading

system. The EPA believes that the protocols in

part 75 can appropriately be applied to

all of the core sources (fossil fuel-fired

electric generating units and industrial

boilers). The issues associated with

monitoring NOX mass emissions from a

stack attached to a boiler, turbine, or

combined cycle unit are the same

regardless of whether that boiler,

turbine, or combined cycle unit is

owned or operated by a utility, by an

independent power producer, or by a

manufacturer. The EPA does

acknowledge that there may be

additional issues associated with

monitoring NOX mass from units such

as process heaters or cement kilns. The RECLAIM program uses very

similar protocols to the ones in part 75

to quantify NOX mass emissions. Both

RECLAIM and part 75 require the use of

NOX CEMS and flow CEMS to quantify

NOX mass emissions from large sources

combusting solid fuel. Both RECLAIM

and part 75 also offer large oil and gas

units an additional option for

monitoring. This option involves the

use of a fuel flowmeter and fuel

sampling and analysis. The RECLAIM

program requires monitoring of source

categories that are in the NOX Budget

Trading Program core group, such as

boilers and turbines, but also requires

monitoring of source categories that are

not in the core group, such as process

heaters and cement kilns.

RECLAIM needed to establish a

standing working group to resolve

issues related to monitoring NOX mass

from such a wide range of source

categories (See South Coast Air Quality

Management District, RECLAIM

Program Three Year Audit and Progress

Report, May 8, 1998). EPA does not

believe that the problems that RECLAIM

has had with monitoring are related to

the protocols that program uses. Rather,

EPA believes these problems are due to

the limited experience that both States

and sources have with monitoring such

a wide range of source categories.

The EPA believes that regardless of

what protocols are used, if States opt to

bring additional source categories into

the trading program, issues related to

monitoring at specific source categories

will arise. These issues will need to be

resolved, thus improving State and EPA

experience with those source categories.

If a State wants to include additional

sources beyond those included in the

core group, then EPA would resolve

issues through the initial certification

process for opt-in units. The EPA will

also provide additional guidance on

specific source categories, sharing the

experiences gained with individual optin units.

Using one basic set of protocols will

make it easier for states, sources and

EPA to work together while gaining

more experience with these sources and

resolving the issues in a cooperative and

consistent manner.

The EPA believes that the most

significant costs associated with

upgrading from an existing NOX

emission rate monitoring system to a

part 75 NOX mass monitoring system are

associated with the need to monitor

NOX mass and would be incurred

regardless of the specific monitoring

protocol that was required. Many

existing CEM rules other than part 75

require sources to monitor NOX

emission rate (in lbs/mmBtu) or NOX

concentration corrected for oxygen (in

ppm)(e.g. monitoring requirements

under Subpart D, Da, Db of part 60). In

order to meet these requirements, a NOX

monitoring system must consist of a

NOX concentration CEM, a diluent CEM

and a data acquisition and handling

system (DAHS). The DAHS is the part

of the system that collects raw monitor

data, performs calculations, and

generates reports.

In order to upgrade an existing system

so that it can monitor NOX mass, a

source must install a flow CEMS, if it

burns solid fuels, or must install either

a flow CEMS or a fuel flow meter if it

burns a homogeneous oil or gas. In

addition, the source would have to
57466 Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations

upgrade its DAHS to reflect the

reporting of NOX mass rather than NOX

emission rate or NOX concentration.

These costs must be incurred, regardless

of the protocol that a source used to

monitor NOX mass.

The EPA believes that a single

monitoring and reporting protocol for

the NOX Budget Trading Program will

keep the costs of upgrading systems to

a minimum. This is because equipment

vendors will be able to create

standardized systems that will be

applicable to all sources in the program,

rather than having to create many

different State- and source-specific

systems. A single monitoring and

reporting protocol will also help ensure

a level playing field for all affected

sources.

For these reasons, part 96 requires all

large units to monitor NOX mass

emissions using CEMS in accordance

with part 75. However, as explained

below, part 75 does offer various

monitoring options for low-emitting or

infrequently operated oil- and gas-fired

units, in addition to CEMS.

c. Commenters Who Do Not Believe

That CEMS Are Necessary. Some

commenters expressed concerns about

requiring CEMS on any unit that does

not currently have a CEMS monitoring

requirement. Suggested alternatives

included the use of stack test data and

emission factors. Some commenters also

suggested the testing and monitoring

provisions of a source’s title V permit.

Response: For large sources, EPA does

not believe that stack test data and

emission factors provide the consistent

and accurate data needed to facilitate a

trading program. Stack test data provide

a one-time assessment of a source’s

emission rate. Emission factors at best

are based on a series of stack tests at

similar units. A unit’s actual emission

rate may fluctuate greatly over time due

to factors such as the way the unit and/

or its associated control equipment is

operated and maintained and the

quality of fuel that the unit burns. An

emission factor or stack test will often

not be representative of that unit’s

actual normal emissions. Continuous

monitoring of actual emissions will

ensure that fluctuations in emission

rates are accounted for. Because CEMS

provide continuous monitoring, they

can also indicate when emission control

equipment is malfunctioning, thus,

helping to ensure that the owners of

units continue to properly operate and

maintain any installed emission control

equipment.

Title V permits incorporate all of the

monitoring requirements to which a

source is subject in order to demonstrate

compliance with its current regulatory

requirements. In addition, where a

source is not subject to any other

monitoring requirements, it sets forth

minimum monitoring requirements. In

many cases the current regulatory

requirements do not require compliance

with a mass emissions limitation.

Therefore, the monitoring requirements

are not designed to demonstrate

compliance with a mass emission

limitation.

Even when a source may have

monitoring requirements designed to

demonstrate compliance with a mass

emissions limitation, the stringency of

these requirements often varies from

source to source and from State to State.

These variations in turn lead to

inconsistencies in sources’ accounting

of mass emissions. This both creates an

uneven playing field for sources and

undermines the integrity of the trading

program.

The EPA believes that it is necessary

for all sources in the trading program to

be subject to accurate and consistent

monitoring requirements designed to

demonstrate compliance with a mass

emission limitation. This will ensure

compliance with the requirements of the

SIP Call and will ensure the integrity of

the trading program.

The EPA does believe that it is

appropriate to provide lower cost

monitoring options for units with low

NOX mass emissions. Part 75 allows

non-CEMS alternatives to quantify NOX

mass emissions for gas and oil fired

units that have low NOX mass emissions

and/or that operate infrequently.

In contrast, EPA does not believe that

the types of protocols set forth in the

Compliance Assurance Monitoring

(CAM) rule, part 64, are appropriate for

a trading program because they were not

designed to quantify mass emissions.

The preamble to the CAM rule further

elaborates why these protocols are not

appropriate for a trading program (62 FR

54915, 54916, 54922).

The EPA believes that the types of

protocols in RECLAIM and the Ozone

Transport Commission’s NOX Budget

Trading Program (‘‘OTC Program’’) are

more appropriate for a trading program

because they were specifically designed

to quantify NOX mass emissions. The

EPA also believes that the flexible

monitoring options offered by part 75

are consistent with the type of

flexibilities offered in RECLAIM and the

OTC Program. RECLAIM requires CEMS

on all units that burn solid fuels and all

units that emit more than 10 tons per

year, regardless of the type of fuel they

burn.. The OTC Program requires CEMS

on all units that burn solid fuels and all

units that do not qualify as peaking

units, that are larger than 250 mmBtu/

hr or that serve generators greater than

25 MW. Like RECLAIM and the OTC

Program, part 75 requires CEMS on all

units that burn solid fuel. Part 75 also

requires the use of CEMS on oil and gas

fired units that emit more than 50 tons

of NOX annually (or for units that only

report during the ozone season, 25 tons

of NOX during the ozone season), or that

don’t qualify as peaking units. In both

the OTC Program and part 75, a peaking

unit is defined as a unit that has a

capacity factor of no more than 10

percent per year averaged over a three

year period and no more than 20

percent in any one year.

The EPA believes that these

exceptions in part 75 provide costeffective monitoring alternatives to

CEMs for small, low mass emitting, or

infrequently used units, and therefore, it

is appropriate that part 96 require all

units to use part 75.

d. Issues Related to Monitoring and

Reporting Needed to Support a Heat

Input Allocation Methodology. For

monitoring and reporting NOX mass

emissions, subpart H of part 75 requires

the use a NOX concentration CEM and

a flow CEM. Since the methodology

does not require the use of heat input,

EPA would not require sources to

monitor or report heat input or NOX

emission rate for a NOX mass emission

reduction program. If a State elects to

use a periodically updating allocation

methodology that utilizes heat input, it

may need to require sources using this

methodology to monitor and report heat

input also.

e. Amendments to Part 75 (1) Summary

of Part 75 Rulemaking. Title IV of the

CAA requires the EPA to promulgate

regulations for continuous emissions

monitoring (CEM). On January 11, 1993,

final rules (40 CFR part 75) were

published (58 FR 3590). Technical

corrections were published on June 23,

1993 (58 FR 34126) and July 30, 1993

(58 FR 40746). A notice of direct final

rulemaking and a notice of interim final

rulemaking making further changes to

the regulations were published on May

17, 1995 (60 FR 26510 and 60 FR 26560,

respectively). Subsequently, on

November 20, 1996, a final rule was

published in response to public

comments received on the direct final

and interim rules (61 FR 59142).

The EPA proposed further revisions to

part 75 on May 21, 1998 (63 FR 28032).

These revisions included a new subpart

H which sets forth procedures for

monitoring NOX mass emissions, which

could be used by sources to comply

with any State or Federal program

requiring measurement of NOX mass

emissions, including the requirements
Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations 57467

of the NOX Budget Trading Rule (part

96). The May 21, 1998 proposed

revisions also proposed to make a

number of other changes that would

affect units that were using part 75 to

comply either with the requirements of

title IV or the requirements of a NOX

mass trading program under title I that

incorporated or adopted the

requirements of part 75. These included

a number of minor changes to simplify

and streamline the rule to make it more

efficient for both affected facilities and

EPA; a new excepted monitoring

methodology that would reduce

monitoring burdens for affected facility

units with low mass emissions; and new

quality assurance requirements to fill in

gaps identified by EPA during

evaluation of the initial implementation

of Part 75.

(2) Schedule For Part 75 Final

Rulemaking. The comment period for

the proposed revisions to part 75 ended

on July 20, 1998. EPA anticipates

completing rulemaking on all of

proposed revisions to part 75 by the end

of the year. However, because the

revisions to subpart H of part 75 relating

to the monitoring and reporting of NOX

mass emissions are integral

requirements of the SIP Call, EPA is

finalizing most of the requirements of

subpart H of part 75 with today’s action.

The EPA is also finalizing a new

excepted monitoring methodology for

units that combust natural gas and or

fuel oil with low mass emissions of NOX

and SO2. These provisions are being

finalized because they are one of the

methodologies that certain gas and oil

units can use to quantify NOX mass

under the new subpart H of part 75.

The EPA is not finalizing the rest of

the proposed revisions to Part 75 at this

time because EPA is still evaluating the

comments received on the proposed

rulemaking. Many of these remaining

provisions will be applicable to any unit

that must use the requirements of part

75 in order to meet the requirements of

title IV or to meet the requirements of

a State or Federal NOX reduction

program that adopts the part 75

requirements. For example, the

proposed revisions would allow a unit

with CEMS to be exempt from the

requirement to perform a linearity test

in any quarter that the combustion unit

for which the CEMs is installed operates

for less than 168 hours. If EPA

ultimately finalizes this proposed

flexibility, it will become available both

to units using part 75 to comply with

title IV and to units using it to comply

with the part 96 model trading rule. As

another example, EPA proposed quality

assurance requirements for moisture

monitors that would be needed if

pollutant concentration (NOX, SO2 or

CO2) were measured on a dry basis and

needed to be converted to a wet basis so

that mass emissions could be

determined using a stack flow meter. If

EPA ultimately finalizes this proposed

requirement it will affect both units

using part 75 to comply with title IV

and units using it to comply with part

96 (or a State or Federal NOX mass

reduction program that adopts part 75).

The EPA is also not yet finalizing the

recordkeeping and reporting

requirements associated with either the

NOX mass monitoring provisions in

subpart H or the low mass emitter

monitoring methodology because EPA

believes that these reporting

requirements should be coordinated

with any changes in the reporting

requirements that result from the

finalization of the rest of proposed

revisions to part 75.

Therefore, EPA has closed the part 75

docket (A–97–35, with respect to the

provisions that are being finalized in

today’s rulemaking: section 75.19, a new

excepted methodology for estimating

emissions for units with low mass

emissions; and subpart H, a new subpart

setting forth provisions for monitoring,

recording and reporting NOX mass

emissions, except where EPA has

reserved final action on related aspects

of these provisions. EPA has not closed

the docket with respect to the other

provisions that were the subject of

EPA’s, May 21, 1998 proposal (63 FR

28032).

(3) Summary of Major Differences

Between Proposed and Final Revisions

to Part 75. The final rule contains two

main differences to the NOX mass

monitoring and reporting provisions

from what was proposed. The first is

that a new methodology for calculating

NOX mass emissions is included. This

methodology utilizes a NOX

concentration CEM and a flow CEM to

calculate NOX mass emissions. The

second is that sources that are not

subject to title IV are not required to

monitor and report data outside of the

ozone season unless otherwise required

to do so by the Administrator or the

permitting authority administering the

NOX mass trading program.

The final rule also contains two main

differences from the proposal with

regard to the new excepted monitoring

methodology for low mass emitters. The

first is that the methodology is

applicable to units with calculated NOX

mass emissions of up to 50 tons, rather

than 25 tons as proposed. The second is

that in lieu of using default rates for

NOX set forth in the rule, the owner or

operator of a unit using this

methodology may instead elect to

determine a unit specific rate by

conducting stack testing. All of these

changes are discussed in greater detail

in Appendix A of this notice. At this

time EPA is only addressing the

comments dealing with the two main

issues for which EPA is finalizing

revisions to part 75, the reporting of

NOX Mass (subpart H) and a new

excepted monitoring methodology for

low emitters (§ 75.19). The EPA intends

to address the rest of the comments on

the part 75 rulemaking in a separate,

future rulemaking. The discussions in

Appendix A also address comments

received in the SNPR docket (A–96–56)

that related specifically to the

monitoring requirements set forth in

part 75.

E. Emission Limitations/Allowance

Allocations

Each State has the ultimate

responsibility for determining the size

of its trading program budget and its

individual source allocations as long as

the trading budget plus emissions from

all other sources do not exceed the

State’s SIP Call budget. The proposed

rule published on May 11, 1998 set

timing requirements identifying when

the allocations should be completed by

each State and submitted to EPA for

inclusion in the NOX Allowance

Tracking System (NATS) and provided

an option specifying how a State might

allocate NOX allowances to the NOX

budget units. Today’s final model rule

clarifies the timing requirements for

submission of allowance allocations to

EPA and provides an optional allocation

approach. Each State remains free to

adopt the Model Rule’s allocation

approach or adopt an allocation scheme

of its own provided it meets the

specified timing requirements, requires

new sources to hold allowances, and

does not allocate more allowances than

are available in the State trading budget.

1. Timing Requirements

In the SNPR, EPA set timing

requirements identifying when a State

would finalize NOX allowance

allocations for each control period in

the NOX Budget Trading Program and

submit them to EPA for inclusion into

the NATS. In developing the proposal,

the Agency reasoned that uniform

timing requirements would be

important to ensure that all NOX budget

units in the trading program would have

sufficient time and the same amount of

time to plan for compliance for each

control period, and sufficient time and

the same amount of time to trade NOX

allowances. After considering a range of

timing requirements, EPA proposed

options that allocated NOX allowances 5
57468 Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations

to 10 years in advance of the applicable

control period. The proposal attempted

to strike a balance between systems that

change the allocations on an annual

basis and systems that establish a single,

permanent allocation.

The proposed rule included the

following timing requirements for the

allocation of NOX allowances: by

September 30, 1999, each participating

State would submit NOX allowance

allocations to EPA for the control

periods in the years 2003, 2004, 2005,

2006, and 2007. After the initial

allocation, two timing requirements

were proposed for allocations following

the year 2007. The option set forth in

the proposed Model Rule would require

a State to submit allocations to EPA for

the control period in the year that is 5

years after the applicable submission

deadline. For example, by January 1,

2003 each State participating in the

trading program would issue its

allocations for the control period in

2008. The State would issue allocations

for the 2009 summer season by January

1, 2004. The second option, discussed

in the preamble of the supplemental

notice, would require the State to

submit five years’ worth of allowance

allocations at a time, every five years,

starting in 2003. For example, by

January 1 , 2003, each State

participating in the trading program

would issue allocations for the control

periods in the years 2008 through 2012.

The supplemental notice solicited

comment on these timing options as

well as the full range of possible timing

requirements (including a single,

permanent allocation system and an

annually changing allocation system).

The supplemental notice also solicited

comment on a provision requiring EPA

to allocate NOX allowances to NOX

budget units if a State were to fail to

meet the timing requirements.

Comments: Although comments

covered the entire range of possible

timing requirements, commenters

generally supported striving for

administrative simplicity and ensuring

sufficient planning horizons for affected

sources, while still addressing the needs

of a changing marketplace. Most

comments fell into one of five

categories.

First, a few commenters favored the

option set forth in the proposed Model

Rule that would update the allocations

each year, five years in advance of the

applicable control period. However,

most of these commenters also

supported a system which would

update the allocations less than five

years prior to the applicable control

period as that would allow more recent

data to be used in the allocations. One

commenter advocated allocating for the

previous season based on current year

data (i.e., allocations would be issued at

the end of the season for the preceding

control period).

Approximately ten commenters

favored the approach which would

issue allowances five to ten years in

advance. This group found that five to

ten years of allocations satisfies the

desire to have a sufficient planning

horizon while still ensuring

responsiveness to changing market

conditions. Utilities generally opposed

allocating single year allowances as it

might be disruptive to utility planning.

The third category of commenters

advocated longer term or permanent

allocations. Most utility and business

commenters favored allocations that

were issued in ten year blocks at a

minimum to provide sufficient time to

plan future activities and amortize

investments. A report submitted by a

State proposed that allocations extend

over the capital life of equipment,

which was at least ten years.

A fourth set of commenters, which

included three States, favored shorter

term allocations. These States

commented that they may want to base

their allocations on more recent data

than that proposed by the Model Rule

and suggested that three years would

provide sufficient planning time for

sources. One State suggested tying

allocations to the submission of

triennial inventories.

A final group of commenters

suggested that no timing requirement

was necessary. They suggested that just

as sources may participate in an

interstate trading program with

allocations based upon different

methodologies, those same sources may

participate in such a program even if

they receive their allowances at

different times or for different periods.

Several State commenters asserted

that September 1999 was too early to

have allocations set. These States

suggested that the allocation process is

difficult and takes longer than one year.

One State suggested that the early

allocation deadline would effectively

prevent States from issuing allowances

based upon output for the first period

because an output approach could not

be developed in time.

Response: Most commenters

supported issuing allowances at least a

couple of years prior to the season in

which they would be used. The

commenters generally cited the goal of

balancing changing market conditions

with providing sufficient planning

horizons, as had the Agency in the

proposal. The EPA agrees that the

certainty in having allowances at least a

couple of years into the future would

provide some predictability for sources

in their control planning and build

confidence in the market. Most of the

State commenters suggested three years

prior to the control season as an

adequate length of time for sources to

know their allocations. The Agency

agrees that a trading system could work

with sources knowing their allocations

three years prior to the control season.

Therefore, EPA has modified its original

proposal to ensure that sources would

always have allowances at least three

years in advance of the use date.

In addition to addressing how many

years in advance the allocations are

determined, the Agency has also

considered whether allocations should

be issued one control period at a time

or for multiple control periods at a time

(e.g., five to ten control periods). In

response to the comments received, the

Agency has determined that it would be

appropriate to set minimum timing

requirements rather than prescribing a

set length of time for all States.

Therefore, the Agency is now requiring

States choosing to participate in the

NOX Budget Trading Program to allocate

a minimum of one summer season of

allowances at a time (at least three years

in advance of the applicable control

period).

Moving from requiring five summer

seasons of allocations (three years in

advance of the first season) to one

summer season of allocations (three

years in advance) has the advantage of

allowing the allocation system to be

updated sooner with more recent data.

This would provide those States that

want to use updating systems to more

fully avail themselves of an updating

system. The system could also

incorporate new sources more quickly,

thus reducing the need for larger new

source set-asides.

However, the Agency has determined

that a State may decide to issue

allowances further into the future than

the one-season minimum period

required by this final rule and still

receive streamlined EPA review of its

trading program. The NOX Allowance

Tracking System will be able to handle

allocations for longer periods.

Therefore, this Final Rule sets out

minimum timing requirements of one

season (three years in advance), but

States may issue allocations in larger

blocks for as many as 30 seasons into

the future and still receive streamlined

EPA review. However, in determining

the length of time for which a State

issues allocations, a State should

consider any potential adjustments that

may occur to its future State budgets.

For example, as stated in Section III.B.5.
Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations 57469

of this preamble, the Agency may

establish new budget levels for the post2007 timeframe. States issuing longterm allocations should address how the

allocations would be adjusted if new

budget levels are established in the

future. The Agency does believe that

having allocations three years prior to

the relevant control period would be the

minimum needed to support an active

multi-state trading market intended to

reduce compliance costs for all States

involved.

The three-year minimum timing

requirement also is compatible with

beginning the program in 2003, with at

least the first year’s allocations

submitted to EPA by September 30,

1999. Sources will know their first

year’s allocations three years prior to the

start of the program, and by April 1,

2003, all sources will have allocations

for at least four seasons—2003, 2004,

2005 and 2006. The Agency maintains

that the first year’s allowances should

be issued by September 30, 1999 to

provide some predictability for sources

in their control planning and build

confidence in the market. It also ties in

with the State’s SIP submittal deadlines.

For States participating in the trading

program, the allowances are an integral

part of the State’s plan to satisfy the

requirements of this SIP call. For

sources in the Trading Program, the

allowances are the mechanism by which

State budget requirements are translated

into source-specific limitations, and

therefore the allocations should be

submitted with the SIP submittals. In

response to States who are worried

about completing allocations in this

time frame, EPA notes that one State in

the OTC resolved its allocations in six

weeks, demonstrating that it is possible

to establish allocations in less than one

year.

Requiring only one year’s worth of

allowances at a time has the added

benefit of being able to more quickly

accommodate States that want to switch

allocation methodologies after the start

of the program. For example, a State

may decide to issue its initial

allocations based on heat input data

because it has not yet finalized an

approach to issuing output-based

allocations. The State could take a few

additional years to refine the alternative

approach to issuing allowances. When

the State is ready to adopt the output

approach, the State would be able to

start using the new approach much

sooner than it would be able to under

a system that issued allocations in larger

blocks.

Therefore, this preamble sets the

following timing requirements for the

allocation of NOX allowances which

will be able to accommodate States that

want to issue allocations one year at a

time as well as States that would like to

issue allocations in larger blocks: by

September 30, 1999, the State would

submit NOX allowance allocations to

EPA for at least the control period of

2003. After this initial allocation, by

April 1 of every year starting in 2001,

the State must, at a minimum, submit

allowance allocations to EPA for the

control period in the year that is three

years after the applicable submission

deadline. For example, by April 1, 2001,

a State would submit allocations for the

control period in 2004. By April 1, 2002,

a State would submit allocations for the

control period in 2005. This minimum

requirement would allow a State to

submit blocks of allowances that

represent any number of years should

the State prefer to do so. For example,

by the September 30, 1999 deadline, a

State could submit allocations for only

the 2003 control period or for multiple

control periods (e.g., the five control

periods of 2003–2007). The SIP would

provide that if the State fails to submit

allocations by the required date, EPA

would allocate allowances based on the

previous year’s allocation within 60

days of the applicable deadline. This

approach would ensure that starting in

2003, all sources would always have at

least three years of allowances in their

accounts.

Today’s Model Rule presents an

allocation approach that satisfies the

minimum timing requirements.

However, the initial allocation is for

three control periods (2003–2005)

because this would avoid updating

allocations on an input basis. Any

variation on the following approach

would be acceptable providing it

satisfies the minimum requirements

specified in the previous paragraph.

After this initial allocation, the model

rule would have the State submit

allowance allocations to EPA for the

control period in the year that is three

years after the applicable submission

deadline. By April 1, 2003, a State

would submit allocations for the control

period in 2006. By April 1, 2004, a State

would submit allocations for the control

period in 2007, and so forth.

2. Options for NOX Allowance

Allocation Methodology

The Agency proposed that the NOX

Budget Trading Rule include a

recommended NOX allowance

allocation methodology. The proposed

Model Rule laid out an example of an

allocation methodology using heat input

data for source allocations. The

preamble to the proposed Model Rule

solicited comment on this methodology

as well as two additional options using

either input or output data for

determining allocations. The first

alternative to using heat input would

base the allocation recommendation on

heat input data for the first five control

periods of the trading program and then

convert the allocations to an output

basis for the control periods after 2007.

The final option would base the

allocation recommendation on output

data for all NOX Budget units from the

start of the trading program. The Agency

also solicited comment on a suggested

schedule for establishing a method for

output-based allocations, and on any

technical or data issues relevant to

output-based allocations, as well as on

the use of a fuel-neutral or outputneutral calculation to determine

allocations for NOX Budget units.

Comments: The Agency received

numerous comments on the issue of

whether to suggest an allocation

recommendation to States.

Approximately 25 commenters

suggested that no recommendation is

necessary. Many of these commenters

emphasized that EPA had no authority

to prescribe an allowance allocation

methodology and a recommendation

could be misinterpreted as a

requirement for SIP approval. Several

commenters requested that EPA clarify

that the SIP approval process will be

consistently applied to all States

regardless of the allocation method

chosen by a State, as long as the total

allocation does not exceed a State’s

trading budget. Approximately half of

the commenters who stated that no

recommendation was necessary

suggested that if EPA were going to

make a recommendation, the

recommendation should be a heat input

approach.

Close to fifty commenters suggested

that an Agency recommendation was a

good idea, but they were divided on the

appropriate methodology. This group

included all the State commenters who

suggested that a recommended approach

was appropriate for use as a default

allocation mechanism by States that did

not determine their own allocations.

Many commenters supported the heat

input approach used in the example in

the supplemental notice. Two State

commenters said that the proposed

example approach was a useful default

for States that did not come up with

their own allocations. Other

commenters suggested that heat input is

an easily understood metric for all

sources and the data is readily available.

However, many suggested that EPA

should recommend an output method

because they believe output-based

allocations tend to reward more efficient
57470 Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations

fuels over fuels that require a higher

heat input to generate the same amount

of electricity. Other reasons cited for

output-based allocations include the

incentive that updating output

allocations provides for reducing

emissions of pollutants such as CO2 and

mercury. Several commenters suggested

that output-based allocations would

allow the environmental goals of the

program to be achieved more costeffectively; their arguments rested upon

assertions that issuing allowances to

non-NOX emitting units in an outputbased system would reduce the need for

NOX controls over time. One State

commenter said that an output approach

was the consensus of participants at

EPA Workshops held prior to drafting of

the Supplemental Notice and therefore

should be the recommended approach

suggested by EPA.

One commenter had a specific

recommendation for an updating

output-based allocation system which

would issue allowances each year for

the current control period.

Administrative simplicity, economic

efficiency, incentives for innovation,

and lower consumer impact were cited

as reasons supporting that position.

Additional commenters favored the

output-based approach but only for

fossil-fuel fired sources and renewables.

Several commenters submitted letters

opposing a ‘‘fuel-neutral’’ policy and

objected to including nuclear sources in

an output allocation to sources. They

stated that a fuel neutral policy would

provide incentives for nuclear

generation which has the potential to

release small amounts of radiation to the

environment as well as the potential for

generation of high-and low-level

radioactive waste.

Response: As was stated in the SNPR,

EPA believes that it is important for as

many States as possible to participate in

the NOX Budget Trading Program. The

Agency recognizes that States have

unanimously favored flexibility in

developing their own allocation

methodologies. Further, the comments

that EPA received in response to the

SNPR (as well as in response to the

workshops held prior to publication of

the SNPR) provided no clear consensus

for one methodology over another.

However, the Agency believes it is

important to provide a model allocation

methodology that States may choose to

use as a guide for their own allocation

process. Several States have commented

that including an example method in

the Model Rule would be useful as a

backup for States who do not come up

with an alternative method of

allocation. An outlined approach in the

Model Rule may also facilitate the

regulatory process within a State that

wants to quickly adopt the Model Rule.

Therefore, today’s Model Rule

includes an optional allocation

methodology. The Agency has carefully

considered arguments for alternative

allocation methods. The EPA would

support a decision by a State to use

either heat input or output data as a

basis for source allocations or for the

State to auction some or all of its

allocation. In determining the basis for

the methodology presented in today’s

Model Rule, EPA has decided to use the

heat input approach because it is

concerned that an output-based

approach has not been fully developed

or made available for public comment.

Further, before issuing a model outputbased allocation approach, the Agency

would need to make several revisions to

current reporting and monitoring

provisions. EPA would have to revise

part 75 to monitor and report

temperature, pressure, and steam heat

output (mmBtu) for units with some or

all of their output as heated steam. EPA

would also need to put in place

procedures which take advantage of the

most accurate data possible. For

example, the Energy Information

Administration (EIA) solicited comment

in a July 17, 1998 Federal Register

Notice on a proposal to make electricity

generating data non-confidential and

publicly available from non-utility

electricity generators (63 FR 38620).

EPA will not know if this information

is available to the Agency or to States

through EIA for some time. If EIA were

to decide that this information should

remain confidential in the future, then

EPA and States would need to collect

their own data from sources.

Additionally, the Agency is currently

unaware of any public databases of

output information besides those for

electrical generation output for certain

electrical generating units. Output

information would only become

available if sources report it directly to

the Agency or to States.

While today’s final Model Rule

includes a heat input approach, the

Agency is continuing to work on

developing an updating output

approach to source allocations. For

States that wish to use output in

developing their source allocations and

are willing to wait for EPA to finalize

such an approach, EPA plans to issue a

proposed system for output-based

allocations in 1999 and finalize an

output-based option in 2000. However,

the Agency’s ability to issue an outputbased approach on this schedule is

contingent upon resolving the issues

and promulgating the necessary rule

changes mentioned in the previous

paragraph.

Assuming EPA finalizes an outputbased option in early 2000, States

wishing to use this output-based system

could adopt the necessary rules, and

output data could be measured and

collected at NOX budget units during

the control periods in the years 2001

and 2002. Output data could then be

available for States to calculate

allocations for the control periods

starting in 2006. Heat-input-based

allocations could be used for the 2003

through 2005 control seasons.

However, this does not prohibit a

State from developing its own outputbased system on a faster timeline. For

example, if a State has developed an

output-based approach for use in its

initial allocations, it may use that

approach. Or, the State may issue its

initial allocation for 2003 using heat

input data and then by April 1, 2001

issue output allocations for the control

periods starting in 2004.

The Agency recognizes that a State’s

choice of when and for what blocks of

time it issues allocations is intertwined

with the choice of allocation

methodology. Several commenters

suggested that more incentives for

generation efficiency and therefore

ancillary environmental benefits (CO2

and mercury reductions) are provided in

an output system with periodic updates,

and those incentives are lost in an heat

input system that is periodically

updated. These commenters suggested

that with a heat-input-based system,

States should issue permanent

allocations rather than updating the

allocations. An allocation system that

issues permanent streams of allowances

(using either a heat input or an output

methodology) would still provide an

incentive for generation efficiency

although perhaps not to the extent that

an updating output system might.

However, if a State issues a permanent

stream of allowances to existing sources,

that State would have to decide how to

address new sources (options include

establishing an allocation set aside or an

auction, or requiring new sources to

obtain allowances from existing

sources).

3. New Source Set-Aside

The Agency proposed an allocation

set-aside account equaling 2 percent of

the State trading program budget for

each control period for new NOx Budget

units as part of its recommended

allocation approach. The concept and

size of the set-aside is included only as

an optional feature of the Model Rule;

however, the Model Rule requires new

sources to hold allowances to cover
Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations 57471

their emissions. The supplemental

notice proposed that allowances from

the set-aside be given out on a firstcome, first-served basis at an emission

rate of 0.15 lb/mmBtu multiplied by a

budget unit’s maximum design heat

input. The source would then be subject

to a reduced utilization calculation so

that a reduction in the emission rate

below 0.15 lb/mmBtu would be

rewarded, but a reduction in utilization

would not. In other words, EPA would

deduct NOx allowances following each

control period based on the unit’s actual

utilization for the control period. After

the deduction, the allocation that had

been granted to the new unit from the

set-aside would equal the product of

0.15 lb/mmBtu and the budget unit’s

actual heat input for the season. EPA

solicited comments on the use of a setaside as part of the recommended

allocation methodology as well as the

proposed size and operation of the setaside.

Comments: The Agency received

many comments regarding the proposal

for a new source set-aside. While several

commenters were opposed to a new

source set-aside because it might bias

control decisions in favor of adding new

sources relative to controlling existing

sources, numerous other commenters

expressed general support for

accommodating new sources with

allowances.

Several of these commenters offered

suggestions for how the set-aside should

be designed. A few commenters stated

that the size of the set-aside should be

related to the timing requirements and

noted that shorter timing requirements

make it easier to accommodate new

growth. One commenter who advocated

annually updating the allocation system

noted that its proposal would eliminate

the need for a new source set-aside.

Some commenters supported the setaside concept but asserted that States

should be able to decide the correct size.

Other commenters agreed with the setaside concept in theory but did not

think the allowances should come from

existing sources.

Additional commenters had specific

proposals for the size of the set-aside.

One commenter suggested that the size

of the set-aside should reflect the actual

growth projected in budget calculations

and that the unused portion of the setaside should be retired. A few

commenters agreed with the proposed 2

percent size.

Several commenters offered

suggestions on how to issue the setaside allowances to new sources. One

commenter suggested that the

allowances should be given to new

sources at the actual emission rate if it

was below the proposed 0.15 lb/mmBtu

level.

Finally, several commenters suggested

that the concept of a set-aside was an

issue that should be left completely up

to the States.

Response: The Agency believes that a

new source set-aside should be large

enough to provide all new units

entering the trading program with

allocations. The Agency maintains that

as much as possible within the context

of the overall trading budget, allocations

should be provided to new sources on

the same basis as that used for existing

units until the time when the new

sources receive an allocation as part of

an updating allocation system.

Therefore, the Agency continues to

include a new source set-aside as part

of its optional allocation methodology

described in the Model Rule. The EPA

proposed the 2 percent set-aside in the

SNPR after looking at the amount of

growth from new sources projected by

the Integrated Planning Model (and

used in the budget determinations) and

estimating how much growth could be

expected over the five year period that

new sources might have to wait before

receiving an allocation. In light of the

allocation methodology and timing

specified in today’s Model Rule as well

as revisions made to the growth factors

used in State budget determinations

since the SNPR, the Agency has reevaluated the size of the new source setaside proposal. The revised Integrated

Planning Model projects approximately

1⁄2 percent annual growth in capacity

utilization for new sources. Given the

timing and optional allocation

methodology specified in today’s Model

Rule, the 2003, 2004, and 2005 set-aside

would need to accommodate any source

that started operating after May 1, 1995.

Assuming the 1⁄2 percent growth rate

projected by IPM, the Agency finds that

a 5 percent set-aside should be large

enough to accommodate all new sources

for the 2003, 2004, and 2005 control

seasons.

After 2005, the new source set-aside

would need to accommodate any source

that commenced operation after May 1

of the control period three years prior to

the control period in which the set-aside

would be available. For example, in

2006, the set-aside should be large

enough to accommodate any source that

commenced operation after May 1,

2003. Assuming the growth rates

predicted by the IPM, the Agency finds

that a 2 percent set-aside should be large

enough to accommodate new source

growth after May 1, 2003.

A 5 percent set-aside provision for the

first three control seasons and 2 percent

for the control periods starting in 2006

is incorporated into today’s Model Rule

as an option States may adopt. However,

States may choose to handle new

sources in any way as long as the

emissions from new sources are subject

to the overall State budget. For example,

some States may choose to issue

allowances for longer periods of time

than that outlined as the minimum

requirement in today’s Model Rule.

These States may find that a 5 percent

set-aside is not sufficient to

accommodate all their new source

growth, and may want to consider a

larger set-aside or alternative means to

accommodate new sources. Or, States

may decide to allocate allowances based

on a new source’s permitted or actual

emissions, which may be lower than

0.15 lb/mmBtu. This would require a

smaller set-aside.

In the model rule set-aside provision,

allowances will be issued to new

sources on a first-come, first-served

basis. Allowances that are not issued to

new sources in the applicable control

period will be returned to the existing

sources in the State on a pro-rata basis

to guard against the possibility of a

disproportionately large set-aside.

The EPA maintains its position that

new sources should receive allowances

at the same rate as that applied to

existing sources (i.e., large electric

generating units would receive

allowances at a 0.15 lb/mmBtu rate,

large non-electric generating units

would receive allowances at the average

emission rate for existing large nonelectric generating units after controls

are in place, as explained in section 4

below). However, to reinforce the

flexibility available on these issues, as

long as a State requires new sources to

hold allowances, the Agency reiterates

that States may have any size set-aside

(including zero), may allocate the setaside in whatever manner they choose,

and may carry over from one year to the

next any amount of allowances (subject

to the banking provisions on this SIP

call). If a State decides to return unused

allowances from a new source set-aside

to existing sources, the State would

indicate to EPA (as the administrator of

the allowance tracking system) what

number of allowances should be

returned to which existing units.

4. Optional NOX Allocation

Methodology in Model Rule

While specific source allocations are

required for States participating in the

NOX Budget Trading Program, the

allocation methodology presented here

is an optional approach that may be

adopted by States. As long as a State (1)

does not allocate more allowances than

are available in the State NOX trading
57472 Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations

budget, (2) requires new sources to hold

allowances, and (3) issues allocations on

a schedule that meets the minimum

timing requirements, the State may

adopt whatever methodology it finds the

most appropriate and still qualify for

inclusion in the NOX Budget Trading

Program.

The Model Rule contains the

following optional allocation

methodology. It differs from the

approach presented in the proposed rule

on the timing provisions, the allocation

methodology for non-electric generating

units, and the size of the optional new

source set-aside. As proposed in the

SNPR, initial unadjusted allocations to

existing NOX Budget units serving

electric generators would be based on

actual heat input data (in mmBtu) for

the units multiplied by an emission rate

of 0.15 lb/mmBtu. For the control

periods in 2003, 2004, and 2005, the

heat input used in the allocation

calculation for large electric generating

units equals the average of the heat

input for the two highest control periods

for the years 1995, 1996, and 1997. Once

the State completes the initial allocation

calculation for all the existing NOX

budget units serving electric generators

for 2003, 2004, and 2005, the State

would adjust the allocation for each unit

upward or downward so that the total

allocations match the aggregate

emission levels apportioned by an

approved SIP to the State’s NOX Budget

units serving electric generators. Then,

the State would adjust the allocation for

each unit proportionately so that the

total allocation equals 95 percent of the

aggregate emission levels apportioned to

the State’s NOX Budget units serving

electric generators (to provide for the 5

percent new source set-aside). A State

would submit the 2003, 2004, and 2005

allocations to EPA by September 30,

1999.

For the control periods starting in

2006, the heat input used in the

allocation calculation for large electric

generating units equals the heat input

measured during the control period of

the year that is four years before the year

for which the allocations are being

calculated. Once the State completes the

initial allocation calculation for all

existing budget units, and the State

adjusts the allocations to match the

aggregate emission levels apportioned to

NOX Budget units serving electric

generators, the State would adjust the

allocation for each unit proportionately

so that the total allocation equals 98

percent of the aggregate emission levels

apportioned to NOX Budget units

serving electric generators (to provide

for the 2 percent new source set-aside).

For reasons explained elsewhere in

today’s rulemaking, EPA determined the

aggregate emission levels for large nonelectric generating units in each State

budget based upon a 60 percent

reduction rather than the 70 percent

proposed in the SNPR. The 60 percent

reduction results in an average emission

rate across the region of 0.17 lbs/mmBtu

for large non-electric generating units.

Therefore, initial unadjusted allocations

to existing large non-electric generating

units would be based on actual heat

input data (in mmBtu) for the units

multiplied by an emission rate of 0.17

lb/mmBtu. For non-electric generating

units subject to the trading program,

1995 heat input data is used in the

allocation calculation for the control

periods 2003, 2004, and 2005 (1995 is

the most recent data the Agency knows

is currently available for non-electric

generating units). Once the State

completes the initial allocation

calculation for all the existing large nonelectric generating units for 2003, 2004,

and 2005, the State would adjust the

allocation for each unit upward or

downward so that the total allocations

match the aggregate emission levels

apportioned by an approved SIP to the

State’s large non-electric generating

units. Then, the State would adjust the

allocation for each unit proportionately

so that the total allocation equals 95

percent of the aggregate emission levels

apportioned to the State’s large nonelectric generating units (to provide for

the 5% new source set-aside). A State

would submit the 2003, 2004, and 2005

allocations to EPA by September 30,

1999.

For the control periods starting in

2006, the heat input used in the

allocation calculation equals the heat

input measured during the control

period of the year that is four years

before the year for which the allocations

are being calculated. Once the State

completes the initial allocation

calculation for all existing budget units,

and the State adjusts the allocations to

match the aggregate emission levels

apportioned to large non-electric

generating units, the State would adjust

the allocation for each unit

proportionately so that the total

allocation equals 98 percent of the

aggregate emission levels apportioned to

large non-electric generating units (to

provide for the 2% new source setaside).

A State would establish a separate

allocation set-aside for new units each

control period. Five percent of the

seasonal trading budget will be held in

a set-aside account for the control

periods in 2003, 2004, and 2005. At the

end of the relevant control period, the

State would submit a NOX allowance

transfer request to EPA to return any

allowances remaining in the account to

the existing sources in the State on a

pro-rata basis.

The allowances would be issued to

new sources on a first-come first-served

basis at a rate of 0.15 lb/mmBtu for NOX

Budget units serving electric generators

and 0.17 lb/mmBtu for large nonelectric generating units multiplied by

the budget unit’s maximum design heat

input. Following each control period,

the source would be subject to a

reduced utilization calculation, in

which EPA would deduct NOX

allowances based on the unit’s actual

utilization. Because the allocation for a

new unit from the set-aside is based on

maximum design heat input, this

procedure adjusts the allocation by

actual heat input for the control period

of the allocation. This adjustment is a

surrogate for the use of actual utilization

in a prior baseline period which is the

approach used for allocating NOX

allowances to existing units.

F. Banking Provisions

As explained in Section III.F.7., EPA

requested comment in the SNPR on

whether and how banking should be

incorporated into the design of the NOX

Budget Trading Program. Banking may

generally be defined as allowing sources

that make emissions reductions beyond

current requirements to save and use

these excess reductions to exceed

requirements in a later time period.

Options ranged from a program without

banking to several variations of a

program with banking, prior to and/or

following the start of the program. The

EPA also requested comment on options

for managing the use of banked

allowances in order to limit the

emissions variability associated with

banking. The EPA specifically proposed

using a ‘‘flow control’’ mechanism in

cases where the potential exists for a

large amount of banked allowances to be

available.

This section addresses how banking

has been incorporated into the NOX

Budget Trading Program based on the

criteria set forth in the NOX SIP call.

1. Banking Starting in 2003

In accordance with the provisions

discussed in III.F.7.a., trading programs

used to comply with the NOX SIP call

may allow banking to start in the first

control period of the program, the 2003

ozone season. The majority of

commenters supported banking in the

context of the NOX Budget Trading

Program. Based on the advantages that

banking can provide, as discussed in the

SNPR and the comments, the NOX
Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations 57473

Budget Trading Program has been

designed to allow banking starting in

the first control period of the trading

program. NOX Budget units that hold

additional NOX allowances beyond

what is required to demonstrate

compliance for a given control period

may carry-over those allowances to the

next control period. These banked

allowances may be used or sold for

compliance in future control periods.

2. Management of Banked Allowances

The NOX SIP call establishes that a

flow control mechanism be paired with

any banking provisions to limit the

potential for emissions to be

significantly higher than budgeted

levels because of banking. This

mechanism allows unlimited banking of

allowances saved through emissions

reductions by sources, but discourages

the ‘‘excessive use’’ of banked

allowances by establishing either an

absolute limit on the number of banked

allowances that can be used each season

or a rate discounting the use of banked

allowances over a given level. In the

SNPR, EPA solicited comment on the

application of flow control in the NOX

Budget Trading Program. Although

many commenters were opposed to any

restrictions on the use of banked

allowances, several commenters stated

that if restrictions were to be imposed,

they would favor flow control as the

most cost-effective, least rigid means of

management. A few commenters added

that, if implemented, flow control

should be applied on a source-by-source

basis so as to avoid penalizing all of the

participants in the trading program for

the excess banking of individual

participants. One commenter stated that

if EPA concludes that there is an

adequate basis for imposing some type

of restriction, it should avoid placing

any absolute limit on the amount of

banked allowances that can be used in

a given season.

The NOX SIP call established that

flow control should be set at the 10

percent level. The effect of setting flow

control at 10 percent of the trading

program budget is that on a season-byseason basis, sources may use banked

allowances or credits for compliance

without restrictions in an amount up to

10 percent of the NOX budget for those

sources in the trading program. Banked

allowances or credits that are used in an

amount greater than 10 percent of the

NOX budget for those sources will have

restrictions on their use.

The following provides a brief

description of exactly how the flow

control mechanism will operate in the

NOX Budget Trading Program. The

number of banked allowances held by

all participants in the multi-state trading

program will be tabulated each year

following the compliance certification

process to determine what percentage

banked allowances are of the overall

multi-state trading budget for the next

year. If this percentage is equal to or

below 10 percent, all banked allowances

may be used in the upcoming control

season on a one allowance for one ton

basis. If this percentage is greater than

10 percent, flow control will be

triggered. In years when flow control is

triggered, a withdrawal ratio will be

established prior to the control period

for which it would apply. The

withdrawal ratio will be calculated by

dividing 10 percent of the total trading

program budget by the total number of

banked allowances. This ratio will be

applied to each compliance or overdraft

account (only accounts used for

compliance) holding banked allowances

as of the allowance transfer deadline at

the end of the control period for which

it applies. Banked allowances in each

account may be used for compliance on

a one-for-one basis in an amount not

exceeding the amount established by the

withdrawal ratio. Banked allowances

used in an amount exceeding that

established by the withdrawal ratio

must be used on a two-for-one basis. By

setting the withdrawal ratio prior to the

applicable control period (in years flow

control is triggered) and applying it at

the time of compliance certification at

the end of the applicable control period,

sources have one full control period to

incorporate the value of using banked

allowances into their operations.

As described above, the NOX Budget

Trading Program applies the flow

control mechanism on a regional basis

and establishes a 2-for-1 discount for

banked allowances that are used in an

amount greater than the flow control

limit. The regional approach for

applying flow control was selected over

the source-by-source approach for the

following reasons:

• EPA believes this option provides

more flexibility to individual sources

than the source-by-source approach. If

the 10 percent limit were placed on

each source based on the source’s

allocation, the limit would be in effect

every year for every source, even when

the amount of banked allowances

throughout the entire trading region was

below 10 percent of the regional trading

budget. In contrast, the regional

approach only applies flow control

when the amount of banked allowances

throughout the region (entire multi-state

trading area) exceeds the 10 percent

limit. In response to the commenter

suggesting that the regional approach

penalizes all participants in the trading

program for the excess banking of

individual participants, EPA notes that

it would be difficult for a few sources

to cause the entire regional bank to

exceed 10 percent of the budget. In

addition, based on the analyses

presented in the RIA, EPA does not

anticipate that flow control is likely to

be triggered. Consequently, flow control

is more of an insurance policy, rather

than a provision that is routinely

expected to be operational.

• The regional approach also

provides flexibility to sources if and

when it is triggered. Because the

withdrawal ratio is set before the

applicable control period but not

applied until the control period’s

allowance transfer deadline, sources

have over seven months to manage the

amount of banked allowances they use

on a 1-for-1 basis versus a 2-for-1 basis.

• EPA believes the regional approach

is also a more universal approach than

the source-by-source approach under a

variety of allocation programs that

States may use in the NOX Budget

Trading Program. To apply the flow

control mechanism on a source-bysource basis, the 10 percent limit would

be applied to each source’s allocation.

In this way, a source could use an

amount of banked allowances up to 10

percent of it’s allocation without

restrictions. Restrictions would be

placed on banked allowances that the

source uses in an amount greater than

10 percent of its allocation. Under

certain allocation programs, States may

choose not to allocate NOX allowances

to new sources and require that these

sources obtain the necessary amount of

NOX allowances for compliance from

the market. By not having an allocation

of NOX allowances, new sources would

be prevented from using banked

allowances under the source-by-source

approach. EPA believes that approaches

to accommodate sources without a fixed

allocation under the source-by-source

flow control approach would overly

complicate the system.

• The regional approach for applying

flow control is also the approach used

in the Ozone Transport Commission’s

(OTC) trading program. Because the

NOX Budget Trading Program is

designed to include States currently

operating in the OTC program, using the

same approach for flow control will

minimize the disruption for these

sources to convert to the NOX Budget

Trading Program.

The other issue for flow control is the

type of restriction to place on banked

allowances used in an amount greater

than the 10 percent limit. The NOX

Budget Trading Program includes the 2-

for-1 discount as the applicable
57474 Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations

restriction. EPA agrees with the

commenters that favored this approach

over using an absolute limit. The EPA

believes the 2-for-1 discount provides

more flexibility for sources to achieve

compliance than is offered by the

absolute limit. The discount is also

beneficial to the environment, when

triggered, by allowing only one ton of

NOX emissions for every two tons

removed. Additionally, the OTC

program uses the 2-for-1 discount.

The following example illustrates

how flow control will be used. For the

year 2006, assume the total trading

program budget across all States equals

300,000 allowances and 35,000

allowances are banked from control

periods prior to the 2006 control period.

Since more than 10 percent (35,000/

300,000 = 11.7%) of the total trading

program budget is banked, a withdrawal

ratio will be established prior to the

2006 control period and will apply to all

compliance and overdraft accounts

(only accounts that may be used for

compliance) holding banked allowances

at the end of the 2006 control period. In

this case, the withdrawal ratio would be

0.86 (determined by dividing 10 percent

of the total trading program budget by

the total number of banked allowances,

or 30,000/35,000). Thus if a source

holds 1,000 banked allowances at the

end of the 2006 control period, it will

be able to use 860 on a 1-for-1 basis, but

will have to use the remaining 140, if

necessary, on a 2-for-1 basis. As a result,

if the source used all its banked

allowances for compliance in the 2006

control period, the 1,000 banked

allowances could be used to cover only

930 tons of NOX emissions (860 + 140/

2). Of course, a source could buy

additional current year allowances to

cover emissions on a 1-for-1 basis or buy

additional banked allowances

(allowances not needed by other sources

for compliance) to increase the amount

of banked allowances it may use on a 1-

for-1 basis.

3. Early Reduction Credits

As described in section III.F.7.c., the

majority of commenters generally

supported the option of awarding early

reduction credits. EPA is allowing, but

not requiring, States to grant early

reduction credits to sources for

reductions in ozone season NOX

emissions prior to the 2003 ozone

season. States may issue early reduction

credits in an amount not exceeding the

State’s compliance supplement pool.

The compliance supplement pool is

further explained in section III.F.6.

Based on the support the commenters

on the NOX Budget Trading Program

expressed for early reduction credits,

EPA is including optional provisions in

the trading program that States may use

for issuing credits. States participating

in the NOX Budget Trading Program that

choose to issue early reduction credits

may follow the methodology included

in part 96 or may develop their own

methodology, provided the State’s

program meets the following

requirements. The State program must

ensure that early reduction credits will

not be issued in an amount exceeding

the State’s compliance supplement pool.

The State program must also meet the

criteria for early reduction credits

discussed in section III.F.7.c. Finally,

the State should notify EPA of the

amount of credits issued to particular

NOX Budget units by no later than May

1, 2003. Early reduction credits shall be

issued to units as allowances for the

2003 control period. For purposes of the

banking provisions, the allowances will

not be considered banked in the 2003

control period. However, any unused

allowances carried from the 2003

control period to the 2004 control

period shall be considered banked as

will be the case for all unused

allowances carried over to the next

control period. Per the requirements

discussed in section III.F.7.c.,

allowances issued for early reduction

credits may be used for compliance by

sources in the 2003 and 2004 control

periods. Any of these allowances that

are not used for compliance in the 2003

or 2004 control periods shall be retired

by EPA from the account in which they

are held.

As discussed in Section III.F.6.b.ii.,

States also have the option of issuing

some or all of the State’s compliance

supplement pool directly to sources

according to the criteria for direct

distribution. Consequently, States

participating in the NOX Budget Trading

Program may also use the direct

distribution option for issuing the

compliance supplement pool. In this

case, the State must notify EPA by May

1, 2003 of the specific NOX Budget units

that will be receiving the direct

distribution.

4. Optional Methodology for Issuing

Early Reduction Credits

The methodology described below is

an optional methodology included in

part 96 that States participating in the

NOX budget Trading Program and

choosing to issue early reduction credits

may follow. States participating in the

NOX Budget Trading Program may also

choose to develop their own

methodology as discussed above. The

following methodology is designed to

meet the criteria for issuing early

reduction credits discussed in section

III.F.7.c. and to provide incentives for a

State’s NOX budget units to generate

early credits in an amount no greater

than the size of the State’s compliance

supplement pool. The State may choose

to issue the entire compliance

supplement pool as early reduction

credits through this methodology, or the

State may choose to reserve some of the

compliance supplement pool to be

issued to sources according to the direct

distribution criteria as described above.

This methodology is applicable for

reductions made during the 2001 and

2002 ozone seasons. NOX budget units

that request early reduction credits will

be required to monitor ozone season

NOX emissions according to the

monitoring provisions of part 75,

subpart H by the 2000 ozone season.

The information from the 2000 ozone

season shall be used to establish a

baseline emission rate for the NOX

budget unit. To be eligible for early

reduction credits, a NOX budget unit

shall reduce its emissions rate in the

2001 and/or 2002 control period(s) no

less than 20 percent below its baseline

emissions rate established for the 2000

ozone season. The size of the early

reduction credit request shall equal the

difference between 0.25 lb/mmBtu and

the unit’s actual emissions rate

multiplied by the unit’s actual heat

input for the applicable control period.

NOX Budget units requesting early

reduction credits should submit the

request to the State by no later than

October 30 of the year for which the

early reductions were generated.

The methodology conforms with the

NOX SIP call’s criteria for early

reduction credits. By requiring that the

reductions be measured using

provisions in part 75, the reductions

will be verified as having actually

occurred and will be quantified

according to the same procedures as

required for compliance with the

general requirements of the NOX Budget

Trading Program. The procedure for

calculating the credit request is

intended to ensure that the reductions

are surplus. Phase II of the title IV NOX

emissions limits are required to be

installed at specific coal-fired boilers by

January 1, 2000. By requiring that an

early reduction credit must be generated

by no less than a 20 percent reduction

below the 2000 baseline emission rate,

credits will only be issued for

reductions that go below emissions

levels achieved for compliance with

title IV requirements. This provision

ensures that the early reduction credits

are only issued for reductions below

existing requirements (i.e., surplus).

Calculating the early credit based on

the difference between 0.25 lb/mmBtu
Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations 57475

and the unit’s actual emissions rate

establishes a standard emissions rate

from which all early reduction credits

are calculated. This approach ensures

that sources with higher NOX emissions

rates prior to the 2001 ozone season are

not provided an opportunity to generate

more early reduction credits than

relatively cleaner sources. In this way,

all sources have an equal opportunity to

generate early reduction credits below a

standard emissions rate.

According to the requirements in the

NOX SIP call, States may not issue early

reduction credits in an amount greater

than the State’s compliance supplement

pool. To ensure this provision is met,

the optional methodology is designed

for States to issue all early reduction

credits following the 2002 ozone season.

By October 30, 2002, a State will have

received all early reduction requests for

both the 2001 and 2002 ozone seasons.

After review of the requests, the State

would issue credit to all valid requests

according to the following procedure. If

the amount of valid requests is less than

the size of the State’s compliance

supplement pool, the State would issue

one allowance for each ton of early

reduction credit requested. If the

amount of valid requests is more than

the size of the State’s pool, the State

would reduce the amount in the credit

requests on a pro-rata basis so that the

requests equal the size of the State’s

pool. After the requests have been

reduced, the State would then issue

allowances based on the remaining size

of each credit request. States would

complete the issuance of allowances for

the early reduction credit requests as

soon as possible following October 30,

2002, but no later than May 1, 2003.

5. Integrating the OTC Program With the

NOX Budget Trading Program’s Banking

Provisions

The OTC NOX Budget Program is a

multi-state, capped NOX trading

program that begins in 1999 and

includes many States subject to today’s

action. By the start of the NOX Budget

Trading Program under the NOX SIP

call, sources in the OTC program will

potentially hold banked NOX

allowances resulting from early

reductions and/or overcontrol with

program requirements. At issue is the

ability of OTC sources to use these

banked allowances in the NOX Budget

Trading Program.

Commenters have supported allowing

OTC sources to use banked allowances

(i.e., early reductions from the 1997 and

1998 ozone seasons and unused

allowances from the 1999 through 2002

ozone seasons) from the OTC program

for compliance in the NOX Budget

Trading Program. Commenters have

stated that because OTC sources will be

subject to a market-based cap-and-trade

program prior to the 2003 ozone season,

it is important to create a smooth

transition from the OTC program to the

NOX Budget Trading Program. They

have suggested discounting OTC Phase

II allowances to make them equivalent

to those achieved under the NOX SIP

call. One OTC State suggested

accomplishing this by adjusting the

OTC banked allowances by a ratio of the

Phase II OTC control requirement to the

Phase III OTC control requirement,

working with EPA to determine the

exact ratio. A few OTC States suggested

that OTC allowances banked in Phase II

could be used as early reduction credits

in the NOX Budget Trading Program. A

commenter from outside the OTC

voiced concern that the use of OTC

allowances banked by sources for the

years 1999 through 2002 could distort

the larger trading market established

under the SIP call.

The EPA believes that the compliance

supplement pool provides the

opportunity to integrate the OTC

program into the NOX Budget Trading

Program by allowing OTC States to

bring their banked allowances into the

NOX Budget Trading Program as early

reduction credits after the 2002 ozone

season. The EPA established two

primary criteria for the generation of

early reduction credits in III.F.7.c.: first,

the credits must be surplus, verifiable,

and quantifiable; and second, a State

may not grant an amount of early

reduction credits in excess of a State’s

compliance supplement pool. EPA

believes that banked allowances held by

sources in the OTC program would

qualify as being surplus, verifiable, and

quantifiable. The banked allowances

would be surplus because they would

represent emissions reductions that go

beyond what is required by the

emissions limitations established by the

OTC program in the applicable ozone

seasons. The banked allowances would

also be verified and quantified

according to the procedures in the OTC

program which are essentially identical

to the requirements that will be in place

under the NOX Budget Trading Program.

As for the second criterion that a State

issue no more early reduction credits

than provided through the compliance

supplement pool, EPA believes this

could be addressed according to the

following procedure. If the number of

banked allowances held by an OTC

State’s NOX Budget units, after the

compliance certification process for the

2002 ozone season, is less than the

number of credits available in the pool

for that State, the NOX budget units in

that State may carry all of their banked

allowances from the OTC program into

the NOX Budget Trading Program. The

banked allowances brought in from the

OTC program would be subtracted from

the State’s compliance supplement pool.

Any remaining credits in the

compliance supplement pool could be

distributed by the OTC State through

the direct distribution option, if

necessary. If, on the other hand, an OTC

State’s NOX Budget units hold banked

allowances from the OTC program in

excess of the amount of credits in the

State’s pool, after the compliance

certification process for the 2002 ozone

season, the State would need to reduce

the amount of allowances eligible for

being carried into the NOX Budget

Trading Program. This could be

achieved by reducing the amount of

banked allowances held by the units on

a pro rata basis so that the number of

allowances carried into the NOX Budget

Trading Program is less than or equal to

the size of the State’s compliance

supplement pool.

The process described above provides

a mechanism for OTC States to use the

compliance supplement pool to carry

banked allowances from the OTC

program as of the end of the compliance

period in 2002 over into the NOX

Budget Trading Program. The EPA

believes this integration acknowledges

the important reductions made in the

OTC program prior to 2003 while

providing similar opportunities for

sources outside the OTC to generate

credits for early reductions. Since all

States in the NOX Budget Trading

Program will have an opportunity to

receive credit for early reductions, EPA

does not believe any market distortion

will occur.

G. New Source Review

Under the New Source Review (NSR)

provisions of section 173 of the CAA, a

new major source or a major

modification to an existing major source

of a particular pollutant that proposes to

locate in an area designated

nonattainment for that pollutant must

offset its new emissions. In the SNPR,

the EPA solicited comment on whether

and how the offset requirement could be

met by sources’ participation in the NOX

Budget Trading Program. The Agency

stated its belief that sources obligated to

obtain NOX offsets under the NSR

program should be able to do so by

acquiring NOX allowances through the

trading program. In essence, the EPA

reasoned that, where a trading program

is a capped system, a new source’s

acquisition of allowances to cover its

increased emissions would necessarily
57476 Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations

result in actual emissions reductions

elsewhere in the system.

The EPA continues to believe that

nonattainment NSR offset requirements

of the CAA can be met using the

mechanism of the NOX Budget Trading

Program. However, there are a number

of complex issues involved with

integrating these programs, for example,

the statutory requirements to obtain

offsets from certain geographic areas

and, depending on the classification of

the 1-hour ozone nonattainment area, at

certain offset ratios. Because the Agency

is continuing to evaluate these issues, it

will not be providing guidance at this

time on integrating these programs;

however, the EPA intends to provide

such guidance as soon as possible. At

that time, the EPA will respond to the

comments received on this topic in the

course of this rulemaking.

VIII. Interaction With Title IV NOX

Rule

The EPA proposed, in the May 11,

1998 supplemental notice, to add a new

§ 76.16 to part 76, the Acid Rain NOX

Emission Reduction Program

regulations. The purpose of the

proposed § 76.16 was to increase

utilities’ flexibility in situations where

units owned or operated by a utility

were subject to both a NOX cap-andtrade program and the Phase II NOX

emission limitations under the Acid

Rain NOX Emission Reduction Program.

Under proposed § 76.16, a State or

group of States could request that the

Administrator relieve all units located

in the State or States and otherwise

subject to the Phase II NOX emission

limitations (under §§ 76.6 and 76.7) of

the requirement to comply with such

emission limitations. The Administrator

could also take this action on his or her

own motion. All Group 1 boilers (i.e.,

tangentially fired or dry bottom wall

fired boilers) would remain subject to

the Phase I NOX emission limitations

(under § 76.5), while Group 2 boilers

(i.e., cell burner boilers, cyclones, wet

bottom boilers, and vertically fired

boilers) would have no NOX limits

under the Acid Rain Program. This

relief would be available if all such

units were subject, under a SIP or a FIP,

to a NOX cap-and-trade program

meeting certain requirements. The NOX

cap-and-trade program had to include,

inter alia, either an annual cap or

seasonal caps that together limited total

annual emissions and a requirement

that each unit use authorizations to emit

(or allowances) to account for all NOX

emissions. In addition, there had to be

a demonstration that total annual NOX

emissions from all units otherwise

subject to the Acid Rain NOX emission

limitations and located in the State or

group of States would, under the NOX

cap-and-trade program, be equal to or

lower than the total number of annual

NOX emissions if the units remained

subject to the Acid Rain NOX emission

limitations. Alternative emission

limitations and NOX averaging plans

under part 76 would not be taken into

account in such a demonstration.

Although the purpose of proposed

§ 76.16 was to provide more flexibility

to utilities consistent with the

requirements of section 407, almost all

utility commenters and many State and

State agency commenters opposed the

proposal. Many commenters argued that

relieving a utility’s units in one State of

the applicability of the Phase II NOX

emission limitation would prevent the

utility from using those units, along

with units that the utility owns or

operates in other States, in an interstate

averaging plan under the Acid Rain

Nitrogen Oxides Emission Reduction

Program. Under section 407(e) of the

CAA, as implemented under § 76.11, a

utility may comply with the Acid Rain

NOX emission limitations by averaging

the emissions of units that the utility

owns or operates in the same State or

other States. Many utilities have

complied, or plan to comply, with the

Acid Rain NOX Emission Reduction

Program by using averaging plans,

including some interstate averaging

plans. However, a unit that has no Acid

Rain emission limitation obviously

cannot be included in an averaging plan

since EPA would have no authority

under title IV to limit the unit’s

emissions, whether on an individualunit or a group-average basis. Further, as

a practical matter, the group average

limit for any given year, which must be

calculated based on the limit applicable

to each individual unit in the averaging

plan, could not reflect any limit for such

a unit. See 40 CFR 76.11(a) (1) and (2)

(allowing only units with Acid Rain

NOX emission limitations in effect to

participate in an averaging plan) and

(d)(1)(ii)(A) (showing calculation of the

group average limit using each unit’s

Acid Rain NOX emission limitation).

In the proposal, EPA attempted to

address the issue of the potential impact

of proposed § 76.16 on averaging plans.

Proposed § 76.16(b)(1)(ii) required that,

in determining whether a NOX cap-andtrade program met the requirements for

granting units relief from the Phase II

NOX emission limitations, the

Administrator must consider ‘‘whether

the cost savings from trading will be

offset by elimination of the ability of an

owner or operator of a unit in the State

or the group of States to use a NOX

averaging plan under § 76.11.’’ 63 FR

25974. However, commenters were still

concerned that the Administrator could,

even after taking this into consideration,

grant the relief over a utility’s objections

and prevent the utility from using an

averaging plan that included the units

for which the Administrator made the

Phase II NOX emission limitations

inapplicable. In light of the utilities’

concerns that proposed § 76.16 would

actually reduce utilities’ compliance

flexibility, albeit under title IV, and

prevent the use of averaging plans

authorized under section 407(e), EPA

has decided not to revise part 76 as

proposed and is not adopting proposed

§ 76.16 as a final rule.

Suggestions by some commenters

that, instead of adopting proposed

§ 76.16, EPA extend the compliance

date under the Acid Rain Program for

the Phase II NOX emission limitations

are rejected as outside the scope of this

rulemaking. As acknowledged by

commenters, that issue was raised in the

rulemaking adopting the Phase II NOX

emission limitations, and the

compliance deadline of January 1, 2000

set in that rulemaking was recently

upheld by the courts in Appalachian

Power v. EPA, 135 F.3d 791 (D.C. Cir.

1998). The SIP call rulemaking did not

include any proposal to alter that date.

On the contrary, EPA stated in the SIP

call:

Obviously, in proposing a new 40

CFR 76.16, EPA is not requesting

comment on any aspect of the December

19, 1996 final rule [i.e., the rule that set

the Phase II NOX emission limitations

and that included an earlier, proposed

version of § 76.16], including any issues

addressed by the Court in Appalachian

Power. 63 FR 25951.

Similarly, commenters’ suggestions

concerning other revisions to the Acid

Rain NOX Emission Reduction Program

regulations (e.g., revisions to change the

averaging provisions in the Acid Rain

regulations to allow averaging among

units that lack common owners or

operators) are rejected as outside the

scope of this rulemaking.

IX. Non-Ozone Benefits of NOX

Emissions Decreases

A. Summary of Comments

One commenter suggested that

drinking water nitrate is not affected by

atmospheric emissions and that the

impacts of eutrophication are unknown,

although no evidence was presented.

Another commenter stated that EPA

should estimate in the RIA the benefits

of the SIP call with respect to the nonozone impacts. One comment was

received stating that EPA should not

consider non-ozone benefits as
Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations 57477

justification for the proposed emission

reductions.

B. Response to Comments and

Conclusion

1. Drinking Water Nitrate

There is no disagreement that high

levels of nitrate in drinking water is a

health hazard, especially for infants.

The contribution of atmospheric

nitrogen (N) deposition to elevated

levels of nitrate in drinking water

supplies can be described as an evolving

impact area. The Ecological Society of

America has included discussion of this

impact in a recent major review of

causes and consequences of human

alteration of the global N cycle in its

Issues in Ecology series (Vitousek, Peter

M., John Aber, Robert W. Howarth, Gene

E. Likens, et al. 1997. Human Alteration

of the Global Nitrogen Cycle: Causes

and Consequences. Issues in Ecology.

Published by Ecological Society of

America, Number 1, Spring 1997). For

decades, N concentrations in major

rivers and drinking water supplies have

been monitored in the United States,

Europe, and other developed regions of

the world. Analysis of these data

confirms a substantial rise of N levels in

surface waters, which are highly

correlated with human-generated inputs

of N to their watersheds. These N inputs

are dominated by fertilizers and

atmospheric deposition.

Increases in atmospheric N deposition

to sensitive forested watersheds

approaching N saturation would be

expected to result in increased nitrate

concentrations in stream water. This

phenomenon has been documented in

the Los Angeles, California area and has

been well-established for areas in

Germany and the Netherlands (Riggan,

P.J., R.N. Lockwood, and E.N. Lopez,

‘‘Deposition and Processing of Airborne

Nitrogen Pollutants in MediterraneanType Ecosystems of Southern

California’’ Environmental Science and

Technology, vol. 19, 1985). Stream

water nitrate concentrations in

watersheds subject to chronic air

pollution in the Los Angeles area were

two to three orders of magnitude greater

than in chaparral regions outside the air

basin.

2. Eutrophication

The EPA believes that the

eutrophication problem associated with

atmospheric nitrogen deposition is well

established. The National Research

Council recently identified

eutrophication as the most serious

pollution problem facing the estuarine

waters of the United States (NRC, 1993).

NOX emissions contribute directly to the

widespread accelerated eutrophication

of United States coastal waters and

estuaries. Atmospheric nitrogen

deposition onto surface waters and

deposition to watershed and subsequent

transport into the tidal waters has been

documented to contribute from 12 to 44

percent of the total nitrogen loadings to

United States coastal water bodies.

Nitrogen is the nutrient limiting growth

of algae in most coastal waters and

estuaries. Thus, addition of nitrogen

results in accelerated algae and aquatic

plant growth causing adverse ecological

effects and economic impacts that range

from nuisance algal blooms to oxygen

depletion and fish kills.

3. Regulatory Impact Analysis

The EPA believes it is important to

note the potential impacts of the

rulemaking, including the substantial

benefits to the environment of several

non-ozone impacts. As described in the

November 7 proposal, in addition to

contributing to attainment of the ozone

NAAQS, decreases of NOX emissions

will also likely help improve the

environment in several important ways:

(1) On a national scale, decreases in

NOX emissions will also decrease acid

deposition, nitrates in drinking water,

excessive nitrogen loadings to aquatic

and terrestrial ecosystems, and ambient

concentrations of nitrogen dioxide,

particulate matter and toxics; and (2), on

a global scale, decreases in NOX

emissions will, to some degree, reduce

greenhouse gases and stratospheric

ozone depletion. These benefits were

also specifically recognized by OTAG,

which in its July 8, 1997 final

recommendations, stated that it

‘‘recognizes that NOX controls for ozone

reductions purposes have collateral

public health and environmental

benefits, including reductions in acid

deposition, eutrophication, nitrification,

fine particle pollution, and regional

haze.’’ However, the benefits of some of

these impacts are very difficult to

estimate. Where possible, EPA provides

estimates of the impacts of the

rulemaking—both ozone and nonozone—in the RIA.

4. Justification for Rulemaking

While EPA believes this information

is important for the public to

understand and, thus, needs to be

described as part of the rulemaking and

RIA, there should be no

misunderstanding as to the legal basis

for the rulemaking, which is described

in Section I, Background, of this notice

and does not depend on the non-ozone

benefits. The non-ozone benefits did not

affect the method in which EPA

determined significant contribution nor

the calculation of the emissions budgets.

X. Administrative Requirements

A. Executive Order 12866: Regulatory

Impacts Analysis

Under Executive Order 12866 (58 FR

51735, October 4, 1993), the Agency

must determine whether a regulatory

action is ‘‘significant’’ and therefore

subject to Office of Management and

Budget (OMB) review and the

requirements of the Executive Order.

The Order defines ‘‘significant

regulatory action’’ as one that is likely

to result in a rule that may:

1. Have an annual effect on the

economy of $100 million or more or

adversely affect in a material way the

economy, a sector of the economy,

productivity, competition, jobs, the

environment, public health or safety, or

State, local, or tribal governments or

communities;

2. Create a serious inconsistency or

otherwise interfere with an action taken

or planned by another agency;

3. Materially alter the budgetary

impact of entitlements, grants, user fees,

or loan programs or the rights and

obligations of recipients thereof; or

4. Raise novel legal or policy issues

arising out of legal mandates, the

President’s priorities, or the principles

set forth in the Executive Order.

In view of its important policy

implications and potential effect on the

economy of over $100 million, this

action has been judged to be a

‘‘significant regulatory action’’ within

the meaning of the Executive Order. As

a result, the final rulemaking was

submitted to OMB for review, and EPA

has prepared a Regulatory Impact

Analysis (RIA) entitled ‘‘Regulatory

Impact Analysis for the Regional NOX

SIP Call (September 1998).’’

This RIA assesses the costs, benefits,

and economic impacts associated with

potential State implementation

strategies for complying with this

rulemaking. Any written comments

from OMB to EPA and any written EPA

response to those comments are

included in the docket. The docket is

available for public inspection at the

EPA’s Air Docket Section, which is

listed in the ADDRESSES Section of this

preamble. The RIA is available in hard

copy by contacting the EPA Library at

the address under ‘‘Availability of

Related Information’’ and in electronic

form as discussed above under

‘‘Availability of Related Information.’’

The RIA attempts to simulate a

possible set of State implementation

strategies and estimates the costs and

benefits associated with that set of
57478 Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations

strategies. The RIA concludes that the

national annual cost of possible State

actions to comply with the SIP call are

approximately $1.7 billion (1990

dollars). The associated benefits, in

terms of improvements in health, crop

yields, visibility, and ecosystem

protection, that EPA has quantified and

monetized range from $1.1 billion to

$4.2 billion. Due to practical analytical

limitations, the EPA is not able to

quantify and/or monetize all potential

benefits of this action.

B. Regulatory Flexibility Act: Small

Entity Impacts

The Regulatory Flexibility Act (5

U.S.C. 601 et seq.) (RFA), as amended

by the Small Business Regulatory

Enforcement Fairness Act (Pub. L. No.

104–121) (SBREFA), provides that

whenever an agency is required to

publish a general notice of proposed

rulemaking, it must prepare and make

available an initial regulatory flexibility

analysis, unless it certifies that the

proposed rule, if promulgated, will not

have ‘‘a significant economic impact on

a substantial number of small entities.’’

5 U.S.C. 605(b). Courts have interpreted

the RFA to require a regulatory

flexibility analysis only when small

entities will be subject to the

requirements of the rule. See, Motor and

Equip. Mfrs. Ass’n v. Nichols, 142 F.3d

449 (D.C. Cir. 1998); United Distribution

Cos. v. FERC, 88 F.3d 1105, 1170 (D.C.

Cir. 1996); Mid-Tex Elec. Co-op, Inc. v.

FERC, 773 F.2d 327, 342 (D.C. Cir. 1985)

(agency’s certification need only

consider the rule’s impact on entities

subject to the rule).

The NOX SIP Call would not establish

requirements applicable to small

entities. Instead, it would require States

to develop, adopt, and submit SIP

revisions that would achieve the

necessary NOX emissions reductions,

and would leave to the States the task

of determining how to obtain those

reductions, including which entities to

regulate. Moreover, because affected

States would have discretion to choose

which sources to regulate and how

much emissions reductions each

selected source would have to achieve,

EPA could not predict the effect of the

rule on small entities.

For these reasons, EPA appropriately

certified that the rule would not have a

significant impact on a substantial

number of small entities. Accordingly,

the Agency did not prepare an initial

RFA for the proposed rule.

For the final rule, EPA is confirming

its initial certification. However, the

Agency did conduct a more general

analysis of the potential impact on small

entities of possible State

implementation strategies. This analysis

is documented in the RIA. The EPA did

receive comments regarding the impact

on small entities. These comments will

be addressed in the Response to

Comment document.

This final rule will not have a

significant impact on a substantial

number of small entities because the

rule does not establish requirements

applicable to small entities. Therefore, I

certify that this action will not have a

significant impact on a substantial

number of small entities.

C. Unfunded Mandates Reform Act

Title II of the Unfunded Mandates

Reform Act of 1995 (Pub. L. 104–4)

(UMRA), establishes requirements for

Federal agencies to assess the effects of

their regulatory actions on State, local,

and tribal governments and the private

sector. Under section 202 of the UMRA,

2 U.S.C. 1532, EPA generally must

prepare a written statement, including a

cost-benefit analysis, for any proposed

or final rule that ‘‘includes any Federal

mandate that may result in the

expenditure by State, local, and tribal

governments, in the aggregate, or by the

private sector, of $100,000,000 or more

* * * in any one year.’’ A ‘‘Federal

mandate’’ is defined under section

421(6), 2 U.S.C. 658(6), to include a

‘‘Federal intergovernmental mandate’’

and a ‘‘Federal private sector mandate.’’

A ‘‘Federal intergovernmental

mandate,’’ in turn, is defined to include

a regulation that ‘‘would impose an

enforceable duty upon State, local, or

tribal governments,’’ section

421(5)(A)(i), 2 U.S.C. 658(5)(A)(i),

except for, among other things, a duty

that is ‘‘a condition of Federal

assistance,’’ section 421(5)(A)(i)(I). A

‘‘Federal private sector mandate’’

includes a regulation that ‘‘would

impose an enforceable duty upon the

private sector,’’ with certain exceptions,

section 421(7)(A), 2 U.S.C. 658(7)(A).

Before promulgating an EPA rule for

which a written statement is needed

under section 202 of the UMRA, section

205, 2 U.S.C. 1535, of the UMRA

generally requires EPA to identify and

consider a reasonable number of

regulatory alternatives and adopt the

least costly, most cost-effective, or least

burdensome alternative that achieves

the objectives of the rule.

The EPA has prepared a written

statement consistent with the

requirements of section 202 of the

UMRA and placed that statement in the

docket for this rulemaking.

Furthermore, as EPA stated in the

proposal, EPA is not directly

establishing any regulatory

requirements that may significantly or

uniquely affect small governments,

including tribal governments. Thus,

EPA is not obligated to develop under

section 203 of the UMRA a small

government agency plan. Furthermore,

as described in the proposal, in a

manner consistent with the

intergovernmental consultation

provisions of section 204 of the UMRA

and Executive Order 12875, EPA carried

out consultations with the governmental

entities affected by this rule. Finally, the

written statement placed in the docket

also contains a discussion consistent

with the requirements of section 205 of

the UMRA.

For several reasons, however, EPA is

not reaching a final conclusion as to the

applicability of the requirements of

UMRA to this rulemaking action. First,

it is questionable whether a requirement

to submit a SIP revision would

constitute a federal mandate in any case.

The obligation for a state to revise its

SIP that arises out of sections 110(a) and

110(k)(5) of the CAA is not legally

enforceable by a court of law, and at

most is a condition for continued

receipt of highway funds. Therefore, it

is possible to view an action requiring

such a submittal as not creating any

enforceable duty within the meaning of

section 421(5)(9a)(I) of UMRA (2 U.S.C.

658 (a)(I)). Even if it did, the duty could

be viewed as falling within the

exception for a condition of Federal

assistance under section 421(5)(a)(i)(I) of

UMRA (2 U.S.C. 658(5)(a)(i)(I)).

As noted earlier, however,

notwithstanding these issues EPA has

prepared the statement that would be

required by UMRA if its statutory

provisions applied and has consulted

with governmental entities as would be

required by UMRA. Consequently, it is

not necessary for EPA to reach a

conclusion as to the applicability of the

UMRA requirements. The analysis

assumes that states would adopt the

control strategies that EPA assumed in

its analyses underlying this action. The

EPA further notes that in two related

proposals also signed today—one

concerning federal implementation

plans if States do not comply with the

SIP call and one concerning the

petitions submitted to the Agency under

section 126 of the CAA—EPA is taking

the position that the requirements of

UMRA apply because both of those

actions could result in the establishment

of enforceable mandates directly

applicable to sources (including sources

owned by state and local governments).

D. Paperwork Reduction Act

The information collection

requirements in this rule have been

submitted for approval to the Office of
Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations 57479

Management and Budget (OMB) under

the Paperwork Reduction Act, 44 U.S.C.

3501 et seq. An Information Collection

Request (ICR) document has been

prepared by EPA (ICR No. 1857.02) and

a copy may be obtained from Sandy

Farmer by mail at Regulatory

Information Division; U.S.

Environmental Protection Agency

(2137); 401 M St., SW., Washington, DC

20460, by email at

farmer.sandy@epa.gov, or by calling

(202) 260–2740. A copy may also be

downloaded from the internet at http:/

/www.epa.gov/icr. The information

requirements are not effective until

OMB approves them.

The EPA believes that it is essential

that compliance with the regional

control strategy be verified. Tracking

emissions is the principal mechanism to

ensure compliance with the budget and

to assure the downwind affected States

and EPA that the ozone transport

problem is being mitigated. If tracking

and periodic reports indicate that a

State is not implementing all of its NOX

control measures beginning with the

compliance date for NOX controls or is

off track to meet its statewide budget by

September 30, 2007, EPA will work

with the State to determine the reasons

for noncompliance and what course of

remedial action is needed.

The reporting requirements are

mandatory and the legal authority for

the reporting requirements resides in

section 110(a) and 301(a) of the CAA.

Emissions data being requested in

today’s rule is not be considered

confidential by EPA. Certain process

data may be identified as sensitive by a

State and are then treated as ‘‘Statesensitive’’ by EPA.

The reporting and record keeping

burden for this collection of information

is described below:

Respondents/Affected Entities: States,

along with the District of Columbia,

which are included in the NOX SIP call.

Number of Respondents: 23.

Frequency of Response: annually,

triennially.

Estimated Annual Hour Burden per

Respondent: 269.

Estimated Annual Cost per

Respondent: $7,140.00.

Estimated Total Annual Hour Burden:

6,197.

Estimated Total Annualized Cost:

$164,190.00.

There are no additional capital or

operating and maintenance costs for the

States, along with the District of

Columbia, associated with the reporting

requirements of this rule. During the

1980s, an EPA initiative established

electronic communication with each

State environmental agency. This

included a computer terminal for any

States needing one in order to

communicate with the EPA’s national

data base systems. Costs associated with

replacing and maintaining these

terminals, as well as storage of data

files, have been accounted for in the ICR

for the existing annual inventory

reporting requirements (OMB # 2060–

0088).

Burden means the total time, effort, or

financial resources expended by persons

to generate, maintain, retain, or disclose

or provide information to or for a

Federal agency. This includes the time

needed to review instructions; develop,

acquire, install, and utilize technology

and systems for the purposes of

collecting, validating, and verifying

information, processing and

maintaining information, and disclosing

and providing information; adjust the

existing ways to comply with any

previously applicable instructions and

requirements; train personnel to be able

to respond to a collection of

information; search data sources;

complete and review the collection of

information; and transmit or otherwise

disclose the information.

An Agency may not conduct or

sponsor, and a person is not required to

respond to a collection of information

unless it displays a currently valid OMB

control number. The OMB control

numbers for EPA’s regulations are listed

in 40 CFR Part 9 and 48 CFR Chapter

15.

Send comments on the Agency’s need

for this information, the accuracy of the

provided burden estimates, and any

suggested methods for minimizing

respondent burden, including through

the use of automated collection

techniques to the Director, Office of

Policy, Regulatory Information Division;

U.S. Environmental Protection Agency

(2137); 401 M St., SW.; Washington, DC

20460; and to the Office of Information

and Regulatory Affairs, Office of

Management and Budget, 725 17th St.,

NW., Washington, DC 20503, marked

‘‘Attention: Desk Officer for EPA.’’

Comments are requested by November

27, 1998. Include the ICR number in any

correspondence.

E. Executive Order 13045: Protection of

Children From Environmental Health

Risks and Safety Risks

1. Applicability of E.O. 13045

The Executive Order 13045 applies to

any rule that EPA determines (1)

‘‘economically significant’’ as defined

under Executive Order 12866, and (2)

the environmental health or safety risk

addressed by the rule has a

disproportionate effect on children. If

the regulatory action meets both criteria,

the Agency must evaluate the

environmental health or safety effects of

the planned rule on children; and

explain why the planned regulation is

preferable to other potentially effective

and reasonably feasible alternatives

considered by the Agency. This

proposed rule is not subject to E.O.

13045, entitled ‘‘Protection of Children

from Environmental Health Risks and

Safety Risks (62 FR 19885, April 23,

1997), because it does not involve

decisions on environmental health risks

or safety risks that may

disproportionately affect children.

2. Children’s Health Protection

In accordance with section 5(501), the

Agency has evaluated the

environmental health or safety effects of

the rule on children, and found that the

rule does not separately address any age

groups. However, the Agency has

conducted a general analysis of the

potential changes in ozone and

particulate matter levels experienced by

children as a result of the NOX SIP call;

these findings are presented in the

Regulatory Impact Analysis. The

findings include population-weighted

exposure characterizations for projected

2007 ozone and PM concentrations. The

population includes a census-derived

subdivision for the under 18 group.

F. Executive Order 12898:

Environmental Justice

Executive Order 12898 requires that

each Federal agency make achieving

environmental justice part of its mission

by identifying and addressing, as

appropriate, disproportionately high

and adverse human health or

environmental effects of its programs,

policies, and activities on minorities

and low-income populations. The

Agency has conducted a general

analysis of the potential changes in

ozone and particulate matter levels that

may be experienced by minority and

low-income populations as a result of

the NOX SIP call; these findings are

presented in the Regulatory Impact

Analysis. The findings include

population-weighted exposure

characterizations for projected ozone

concentrations and PM concentrations.

The population includes census-derived

subdivisions for whites and non-whites,

and for low-income groups.

G. Executive Order 12875: Enhancing

the Intergovernmental Partnerships

Under Executive Order 12875, EPA

may not issue a regulation that is not

required by statute and that creates a

mandate upon a State, local or tribal

government, unless the Federal
57480 Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations

government provides the funds

necessary to pay the direct compliance

costs incurred by those governments. If

the mandate is unfunded, EPA must

provide to the Office of Management

and Budget a description of the extent

of EPA’s prior consultation with

representatives of affected State, local

and tribal governments, the nature of

their concerns, copies of any written

communications from the governments,

and a statement supporting the need to

issue the regulation. In addition,

Executive Order 12875 requires EPA to

develop an effective process permitting

elected officials and other

representatives of State, local and tribal

governments ‘‘to provide meaningful

and timely input in the development of

regulatory proposals containing

significant unfunded mandates.’’

Today’s rule does not create a

mandate on State, local or tribal

governments. As explained in the

discussion of UMRA (Section X.C), this

rule does not impose an enforceable

duty on these entities. Accordingly, the

requirements of section 1(a) of

Executive Order 12875 do not apply to

this rule.

H. Executive Order 13084: Consultation

and Coordination With Indian Tribal

Governments

Under Executive Order 13084, EPA

may not issue a regulation that is not

required by statute, that significantly or

uniquely affects the communities of

Indian tribal governments, and that

imposes substantial direct compliance

costs on those communities, unless the

government provides the funds

necessary to pay the direct compliance

costs incurred by the tribal

governments. If the mandate is

unfunded, EPA must provide to the

Office of Management and Budget, in a

separately identified section of the

preamble to the rule, a description of

the extent of EPA’s prior consultation

with representatives of affected tribal

governments, a summary of the nature

of their concerns, and a statement

supporting the need to issue the

regulation. In addition, Executive Order

13084 requires EPA to develop an

effective process permitting elected and

other representatives of Indian tribal

governments ‘‘to provide meaningful

and timely input in the development of

regulatory policies on matters that

significantly or uniquely affect their

communities.’’

Today’s rule does not significantly or

uniquely affect the communities of

Indian tribal governments. The rule

applies only to certain States, and does

not require Indian tribal governments to

take any action. Moreover, EPA does

not, by today’s rule, call on States to

regulate NOX sources located on tribal

lands. Accordingly, the requirements of

section 3(b) of Executive Order 13084

do not apply to this rule.

The only circumstance in which the

rule might even indirectly affect sources

on tribal lands would be if the budget

set for one or more of the 23

jurisdictions reflects assumed emissions

reductions from NOX sources on tribal

lands located within the exterior

boundaries of those States. The EPA is

not aware of any such sources.

However, to address the possibility that

one or more of the State budgets reflects

reductions from such sources, and

because any such State generally would

not have jurisdiction over such sources

(see EPA’s rule promulgated under CAA

section 301(d), 63 FR 7254, February 12,

1998), EPA will consider any request to

revise as appropriate the budget and

base year 2007 emissions inventory for

such a State, based on a demonstration

that the State does not have authority to

regulate those sources.

I. Judicial Review

Section 307(b)(1) of the CAA indicates

which Federal Courts of Appeal have

venue for petitions of review of final

actions by EPA. 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) such action is

locally or regionally applicable, if ‘‘such

action is based on a determination of

nationwide scope or effect and if in

taking such action the Administrator

finds and publishes that such action is

based on such a determination.’’

Any final action related to the NOX

SIP call is ‘‘nationally applicable’’

within the meaning of section 307(b)(1).

As an initial matter, through this rule,

EPA interprets section 110 of the CAA

in a way that could affect future actions

regulating the transport of pollutants. In

addition, the NOX SIP call, as proposed,

would require 22 States and the District

of Columbia to decrease emissions of

NOX. The NOX SIP call also is based on

a common core of factual findings and

analyses concerning the transport of

ozone and its precursors between the

different States subject to the NOX SIP

call. Finally, EPA has established

uniform approvability criteria that

would be applied to all States subject to

the NOX SIP call. For these reasons, the

Administrator also is determining that

any final action regarding the NOX SIP

call is of nationwide scope and effect for

purposes of section 307(b)(1). Thus, any

petitions for review of final actions

regarding the NOX SIP call 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.

J. Congressional Review Act

The Congressional Review Act, 5

U.S.C. 801 et seq., as added by the Small

Business Regulatory Enforcement

Fairness Act of 1996, generally provides

that before a rule may take effect, the

agency promulgating the rule must

submit a rule report, which includes a

copy of the rule, to each House of the

Congress and to the Comptroller General

of the United States. The EPA will

submit a report containing this rule and

other required information to the U.S.

Senate, the U.S. House of

Representatives, and the Comptroller

General of the United States prior to

publication of the rule in the Federal

Register. A ‘‘major rule’’ cannot take

effect until 60 days after it is published

in the Federal Register. This action is a

‘‘major rule’’ as defined by 5 U.S.C.

§ 804(2). This rule will be effective

December 28, 1998.

K. National Technology Transfer and

Advancement Act

Section 12(d) of the National

Technology Transfer and Advancement

Act of 1995 (NTTAA), Pub. L. No. 104–

113, section 12(d) (15 U.S.C. 272 note)

directs EPA to use voluntary consensus

standards in its regulatory 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, and business

practices) that are developed or adopted

by voluntary consensus standards

bodies. The NTTAA directs EPA to

provide Congress, through OMB,

explanations when the Agency decides

not to use available and applicable

voluntary consensus standards.

This final rulemaking sets forth a

model trading program including

environmental monitoring and

measurement provisions that States are

encouraged to adopt as part of their

SIPs. If States adopt those provisions,

sources that participate in the trading

program would be required to meet the

applicable monitoring requirements of

part 75. In addition, this final

rulemaking requires States that choose

to regulate certain large stationary

sources to meet the requirements of the

SIP call to use part 75 to ensure

compliance with their regulations. Part

75 already incorporates a number of

voluntary consensus standards. In
Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations 57481

addition, EPA’s proposed revisions to

part 75 proposed to add two more

voluntary consensus standards to the

rule (see 63 FR at 28116–17, discussing

ASTM D5373–93 ‘‘Standard Methods

for Instrumental Determination of

Carbon, Hydrogen and Nitrogen in

laboratory samples of Coal and Coke,’’

and API Section 2 ‘‘Conventional Pipe

Provers’’ from Chapter 4 of the Manual

for Petroleum Measurement Standards,

October 1988 edition). The EPA’s

proposed revisions to part 75 also

requested comments on the inclusion of

additional voluntary consensus

standards. The EPA is finalizing some

revisions to part 75 now, including the

incorporation of two voluntary

consensus standards, in response to

comments submitted on the proposed

part 75 rulemaking:

(1) American Petroleum Institute

(API) Petroleum Measurement

Standards, Chapter 3, Tank Gauging:

Section 1A, Standard Practice for the

Manual Gauging of Petroleum and

Petroleum Products, December 1994;

Section 1B, Standard Practice for Level

Measurement of Liquid Hydrocarbons in

Stationary Tanks by Automatic Tank

Gauging, April 1992 (reaffirmed January

1997); Section 2, Standard Practice for

Gauging Petroleum and Petroleum

Products in Tank Cars, September 1995;

Section 3, Standard Practice for Level

Measurement of Liquid Hydrocarbons in

Stationary Pressurized Storage Tanks by

Automatic Tank Gauging, June 1996;

Section 4, Standard Practice for Level

Measurement of Liquid Hydrocarbons

on Marine Vessels by Automatic Tank

Gauging, April 1995; and Section 5,

Standard Practice for Level

Measurement of Light Hydrocarbon

Liquids Onboard Marine Vessels by

Automatic Tank Gauging, March 1997;

for § 75.19 and,

(2) Shop Testing of Automatic Liquid

Level Gages, Bulletin 2509 B, December

1961 (Reaffirmed October 1992), for

§ 75.19.

These materials are available for

purchase from the following address:

American Petroleum Institute,

Publications Department, 1220 L Street

NW, Washington, DC 20005–4070.

These standards are used to quantify

fuel use from units that have low

emissions of NOX and SOX.

The EPA intends to finalize other

revisions to part 75 in the near future

and address comments related to the

proposed voluntary consensus

standards and to additional voluntary

consensus standards at that time.

Consistent with the Agency’s

Performance Based Measurement

System, 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.

The 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 in advance

before they may be used under part 75.

List of Subjects

40 CFR Part 51

Air pollution control, Administrative

practice and procedure, Carbon

monoxide, Environmental protection,

Intergovernmental relations, Nitrogen

dioxide, Ozone, Particulate matter,

Reporting and recordkeeping

requirements, Sulfur oxides,

Transportation, Volatile organic

compounds.

40 CFR Parts 72 and 75

Air pollution control, Carbon dioxide,

Continuous emissions monitors, Electric

utilities, Environmental protection,

Incorporation by reference, Nitrogen

oxides, Reporting and recordkeeping

requirements, Sulfur dioxide.

40 CFR Part 96

Environmental protection,

Administrative practice and procedure,

Air pollution control, Nitrogen dioxide,

Reporting and recordkeeping

requirements.

Dated: September 24, 1998.

Carol M. Browner,

Administrator.

Appendix A to the Preamble—Detailed

Discussion of Changes to Part 75

The following discussion addresses

the comments received both on the

SNPR (68 FR 25902) and the proposed

part 75 revisions (68 FR 28032) that

relate to the monitoring of NOX mass

emissions. In addition, it addresses the

comments received on the excepted

monitoring methodology for low mass

emitting units that would apply to both

units affected by title IV of the CAA and

to units affected by a State or Federal

NOX mass reduction program that

adopted or incorporated the

requirements of this part.

I. NOX Mass Monitoring and Reporting

Provisions

Commenters raised four main issues

with the proposed NOX mass

monitoring and reporting provisions in

subpart H. The first issue has to do with

the appropriate monitoring

requirements necessary to support a

NOX mass monitoring program,

particularly in light of the fact that

many of the units that would be subject

to a program based on Part 96 are not

currently monitoring NOX mass

emissions. The second has to do with

using a NOX concentration CEMS and a

flow CEMS to calculate NOX mass. The

third has to do with the requirement to

report NOX mass emissions year round

even though the ozone season is only 5

months long. The final issue has to do

with the requirement to have petitions

for alternatives to part 75 be approved

by both the state permitting authority

and by EPA.

A. Background on Use of Part 75 to

Monitor and Report NOX Mass

Emissions

Subpart H of the proposed part 75

rule set forth general monitoring and

reporting requirements that sources

subject to a State or Federal NOX mass

emission reduction program could

incorporate or adopt into that program.

Several commenters argued that it was

inappropriate to require sources, who

were not already required to meet the

requirements of part 75, to meet those

requirements for purposes of a state

program.

Commenters who suggested that it

was inappropriate to require a source

that is not already subject to part 75 to

meet the requirements of part 75 for

purposes of a state program suggested

that the State should decide what

requirements the source needs to meet.

The EPA agrees that this would be

appropriate in the case of a program that

only affected that state. For instance, if

a State was developing a NOX reduction

program to address its own nonattainment problem, it would not be

necessary to adopt requirements that

were consistent across a larger

geographic area. However, in a multistate program, particularly a multi-state

trading program which engages in

interstate commerce like the one set

forth in part 96, EPA believes it is

necessary to account for emissions in a

consistent manner across the whole

region. This ensures that all sources that

participate in the trading program

account for their emissions in a

consistent manner, ensuring both

integrity in the trading program and a

level playing field for all program

participants. Therefore, EPA believes

that it is necessary to create one set of

consistent monitoring and reporting

requirements that can be used for such

a program. This is consistent with the

way the Act mandated that a multi-state

trading program be implemented under

Title IV. It is also consistent with the
57482 Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations

approach taken in implementing other

emissions standards, such as the new

source performance standards that affect

many states. This approach also makes

it easier for states designing their

programs since they would not have to

reinvent the monitoring requirements in

each case.

Commenters who suggested that part

75 did not provide enough flexibility

focused on three areas: they suggested

that other programs such as RECLAIM

or the OTC trading program provided

more flexible non-CEMS options for

units that operated infrequently or had

low NOX mass emissions; they

suggested that sources should be

allowed to use predictive emissions

monitoring systems (PEMS); and they

suggested that sources should be

allowed to use coal sampling and

weighting to determine heat input.

The EPA believes that the flexibilities

offered by part 75 are consistent with

the type of flexibilities offered in

RECLAIM and the OTC Program.

RECLAIM requires CEMS on all units

that emit more than 10 tons of any

individual pollutant per year. The OTC

Program requires CEMS on all units that

do not qualify as peaking units that are

larger than 250 mmBtu or serve

generators greater than 25 MWs. Subpart

H of part 75 allows non-CEMS

alternatives for units that have

emissions less than 50 tons per year of

NOX. If a unit is not required to report

SO2 and CO2 for Acid Rain compliance,

then the unit may use the low mass

emissions provisions of Part 75 if its

NOX emissions are less than 50 tons per

year. Part 75 also allows non-CEMS

alternatives for units that qualify as

peaking units. In both the OTC Program

and part 75, a peaking unit is defined as

a unit that has a capacity factor of no

more than 10 percent per year averaged

over a three year period and no more

than 20 percent in any one year. The

EPA believes that these options provide

cost effective monitoring methodologies

for small or infrequently used units.

While commenters who supported the

use of PEMS and the use of coal

sampling and weighting asserted that

these methodologies would provide data

equivalent to that provided by the

methodologies in Part 75, none of the

commenters provided any data to justify

this claim. Therefore EPA is not adding

specific requirements that would allow

either of these methodologies. It should

be noted that subpart E of part 75 does

provide a means for a source to

demonstrate that an alternative

methodology such as PEMS or coal

sampling and weighting is equivalent to

CEMS. Subpart E of part 75 is consistent

with Performance Based Measurement

Systems criteria. Any source wishing to

use an alterative methodology may

petition the agency under subpart E of

part 75.

B. Background on Use of a NOX

Concentration CEMS and a Flow CEMS

to Calculate NOX Mass

Subpart H of the proposed part 75

rule called for sources in the NOX

Budget Program to monitor NOX

emission rate in lb/mmBtu using a NOX

concentration monitor and a diluent

monitor, and then to multiply this by

heat input, calculated using a flow

monitor and a diluent monitor. Under

this proposal, sources would then

calculate NOX mass emissions by

multiplying the hourly NOX emission

rate by the hourly heat input to obtain

the pounds of NOX emitted during the

hour. The EPA also requested comment

on whether it would be appropriate for

sources in the NOX Budget Program to

use the NOX concentration monitor and

flow monitor without a diluent monitor

to calculate NOX mass emissions. This

is analogous to the Acid Rain Program’s

current approach to monitoring SO2

mass emissions.

Commenters recommended that the

Agency require sources to determine

NOX mass emissions from pollutant

concentration and stack gas volumetric

flow. The commenters stated that this

approach would be more accurate, more

familiar to sources, and more consistent

with the SO2 mass emissions monitoring

in the existing part 75.

The Agency agrees that using NOX

pollutant concentration and volumetric

flow is an appropriate method for

monitoring NOX mass emissions.

Today’s final rule includes provisions in

Subpart H and Section 8 of Appendix F

of part 75 to allow sources to choose one

of several options for monitoring and

calculating NOX mass emissions.

Sources may monitor NOX mass

emissions by using either:

All Units

• A NOX pollutant concentration

monitor and a volumetric flow monitor,

or a NOX concentration monitor and a

diluent monitor to calculate NOX

emission rate in lb/mmBtu, and a flow

monitor and a diluent monitor to

calculate heat input; or

• A NOX concentration monitor and a

diluent monitor to calculate NOX

emission rate in lb/mmBtu, and a fuel

flow meter and oil or gas sampling and

analysis to calculate heat input; or

Oil/Natural Gas Fired Units

• Peaking units may use NOX to load

correlation procedures from Appendix E

of part 75 for NOX emission rate, and a

fuel flow meter and oil or gas sampling

and analysis to calculate heat input; or

• Units with less than 50 tons of Nox

and 25 tons of SO2 may use emission

rates multiplied by either the maximum

rated heat input capacity of the unit or

by the actual heat input of the unit

which may be determined on a longer

term basis than a single hour.

The EPA decided to allow sources

several options so that they could use

monitoring equipment that is already

installed under part 75 to the greatest

extent possible.

In implementing these options, a

source would need to designate a

primary approach to calculating NOX

mass emissions. For example, the

designated representative of a coal-fired

unit could choose to designate a

primary monitoring approach under

Option 1 (pollutant concentration

monitor and diluent monitor, and

diluent monitor and flow monitor). The

designated representative could then

use a (pollutant concentration monitor

and flow monitor) as a backup

monitoring approach. This would be

useful for periods when the diluent

monitor is not operating properly,

where NOX emission rate data in lb/

mmBtu would not be available, but NOX

mass emission data in lb could still be

available. The OTC NOX Budget

Program allows this approach (see

docket A–97–35 item II-I–7).

In order to make monitoring as

consistent as possible between the first

two approaches for monitoring NOX

mass emissions using continuous

emission monitoring systems (CEMS),

EPA is making additional changes to

part 75. First, the Agency is adding

language in Section 8 of Appendix F

that specifies the calculations for NOX

mass emissions using either approach.

Second, EPA is requiring sources that

use a NOX pollutant concentration

monitor and a flow monitor as the

primary method for calculating NOX

mass emissions to substitute for missing

NOX pollutant concentration data using

the same missing data procedures as for

NOX CEMS (lb/mmBtu) under

§§ 75.31(c), 75.33(c) and Appendix C.

Third, the Agency is establishing a

relative accuracy testing requirement for

NOX pollutant concentration monitors

that are used to calculate NOX mass

emissions independently of a NOX

CEMS (lb/mmBtu). The NOX pollutant

concentration monitors will need to

meet a relative accuracy of 10.0 percent

to pass the relative accuracy test audit

(RATA). They will need to meet a

relative accuracy of 7.5 percent to

perform a RATA on an annual basis

instead of a semi-annual basis. Because

the vast majority of NOX CEMS (lb/
Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations 57483

mmBtu) and SO2 pollutant

concentration monitors routinely meet a

relative accuracy of 7.5 percent or less,

the Agency concludes that it will also be

possible for a NOX pollutant

concentration monitor, which is part of

a NOX CEMS, to meet this standard.

Fourth, EPA requires these sources to

test their NOX pollutant concentration

monitor and flow monitor for bias. If the

monitor is found to be biased low, then

the source must either fix the monitor

and retest it to show it is not biased, or

apply a bias adjustment factor to hourly

data. These changes to part 75 make

monitoring consistent between the

different monitoring approaches using

CEMS, prevent underestimation of

emissions, preserve monitoring

accuracy, and take advantage of

approaches already developed for other

monitoring systems that will be familiar

to sources.

The EPA decided to allow sources to

calculate NOX mass emissions using

NOX concentration and flow rate for

several reasons:

• This approach would allow sources

to remove bias due to the diluent

monitor from calculations of NOX mass

emissions.

• Sources affected by the NOX Budget

Program, but not by the Acid Rain

Program, such as industrial boilers, may

be able to simplify their recordkeeping

and reporting because they will not

need to calculate or report NOX

emission rate in lb/mmBtu for each hour

for the trading program.

• Sources will be able to maintain

higher availability of quality-assured

NOX mass emission data, because they

will not need to substitute missing data

for purposes of NOX mass emissions

when data are not available from the

diluent monitor.

• As the commenters suggested, this

approach is more analogous to

monitoring for SO2 mass emissions in

the Acid Rain Program.

Because this approach is already

allowed under the OTC NOX Budget

Program, EPA already has accounted for

this possibility in the electronic data

reporting format and in its

computerized Emission Tracking

System.

For these reasons, the Agency believes

that it is appropriate to allow sources

the option of monitoring and calculating

NOX mass emissions using NOX

pollutant concentration and flow

monitors.

Sources using this approach may still

be required to install maintain and

operate a diluent monitor to calculate

heat input if required to do so by their

state for purposes of obtaining data

needed to support allocation of NOX

allowances.

C. Background on Year Round

Reporting of NOX Mass Emissions

The proposal would have required all

units to report NOX mass emissions on

an annual basis rather than on an ozone

season basis. One commenter noted that

since the proposed SIP call would not

require emission reductions outside of

the ozone season it is not necessary to

report NOX mass emissions outside of

the ozone season. The EPA agrees that

solely for the purposes of an ozone

program, it may not be necessary to

report NOX mass emissions outside of

the ozone season except if a source

wants to qualify for the low mass

emissions provision. However the

requirements of subpart H could be used

to support NOX mass emission

reduction programs where reductions

would be required annually. In

addition, the monitoring and reporting

requirements could be used to help

consolidate other State or Federal

reporting that would be required on an

annual basis. Therefore in the final rule

the requirements of subpart H have been

modified so that they no longer require

annual reporting of NOX mass

emissions, but rather defer to the State

or Federal rule that is incorporating

these requirements to define the

applicable time period for reporting.

In addition a new section has been

added to subpart H that details how the

requirements of part 75, which are

designed to be used annually, should be

used if monitoring and reporting is

being done for only part of the year.

Some of the most significant

differences include:

• Owners and operators of units using

the fuel sampling procedures in

Appendix D must ensure that they have

accurate fuel sampling information at

the beginning of the ozone season. This

requires either sampling the fuel tank

itself before the start of the ozone season

or meeting the requirements to sample

fuel deliveries on a year round basis.

• Historical lookback periods for

missing data periods only need to

include data from the ozone season.

However, if a monitor is out of control

at the beginning of the season, historical

data from seven months ago may

represent significantly different

operating conditions (e.g. fuel burned or

use of control equipment). Therefore the

AAR would have to certify that the

operating conditions are representative

of the previous years operating

conditions. If the conditions are not

representative, the standard missing

data procedures could not be used. In

this case maximum potential NOX mass

emissions would have to be substituted.

• The owner or operator of a unit

must ensure that the monitors used for

monitoring and reporting are in control.

Since CEMS require ongoing quality

assurance to ensure that they are

operating properly, owners and

operators of units that do not meet this

requirement during the non-ozone

season will have to recertify their

monitors before the start of the ozone

season.

D. Background on Requiring EPA and

the State Permitting Authority to

Approve Alternatives to Part 75

The proposal would have required

owners and operators of units that are

not subject to the requirements of title

IV of the CAA that wish to petition for

an alternative to any of the requirements

of part 75 to petition both the state

permitting authority and the

Administrator. Several commenters

suggested that approval of one or the

other should suffice. Some of the

commenters also noted that the

requirements were different for units

affected by title IV, who are only

required to petition the Administrator.

The EPA agrees that the requirements

for units affected by title IV and units

not affected by title IV are inconsistent.

Because of different requirements of the

Act this inconsistency is necessary. The

EPA has the sole authority to grant

petitions to units affected by title IV

under § 75.66 of part 75. If a State

incorporates those monitoring

requirements into its State rules, this

still does not give it the authority to

change or waive the monitoring

requirements for a unit subject to title

IV. However, recognizing that granting a

petition affects the accounting of NOX

mass emissions for a State program, EPA

does intend to work cooperatively with

State agencies on petition requests that

could affect monitoring and reporting of

NOX mass emissions.

For sources not affected by title IV

that are complying with the

requirements of subpart H because they

have been adopted or incorporated into

a State SIP, neither EPA nor the State

has sole authority to approve a petition

for an alternative. While the State does

have the authority to set forth specific

monitoring and reporting requirements

in a SIP and submit those requirements

for EPA approval, a State does not have

the discretion to modify the SIP by

changing or waiving those monitoring

and reporting requirements without

obtaining EPA approval. Likewise, EPA

does not have sole authority to revise a

SIP since the primary responsibility to

develop and implement a SIP is granted
57484 Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations

to the States under the CAA. The EPA

is however required by the CAA to

review and approve or disapprove SIP

revisions. Since a petition to change or

waive unspecified requirements related

to monitoring and reporting can not be

approved as part of the original SIP

approval process, EPA must be involved

in any approvals of alternatives to the

SIP.

In addition to the title I requirements

for EPA to be involved in approval of

petitions for alternatives to part 75,

there are several other reasons that EPA

needs to be involved. The first is that

since EPA is administering the

emissions data collection system under

part 75, EPA must ensure that any

changes to the reporting requirements

can be handled by the emissions

tracking system that EPA maintains.

Secondly, in order to ensure the

integrity of a multi-state market based

system and to ensure that participants

in the system are treated equitably, it is

important to ensure that sources are

treated equitably from State to State.

Therefore, if interstate trading is taking

place EPA clearly has a role in

approving petitions for alternatives to

ensure that sources are treated

consistently from state to state when

engaging in such interstate commerce.

II. Low Mass Emissions Excepted

Monitoring Methodology

A. Background

In the January 11, 1993 Acid Rain

permitting rule, EPA provided for a

conditional exemption from the

emissions reduction, permitting, and

emissions monitoring requirements of

the Acid Rain Program for new units

having a nameplate capacity of 25 MWe

or less that burn fuels with a sulfur

content no greater than 0.05 percent by

weight, because of the de minimis

nature of their potential SO2, CO2 and

NOX emissions (see 58 FR 3593–94 and

3645–46). Moreover, in the January 11,

1993 monitoring rule, EPA allowed gasfired and oil-fired peaking units to use

the provisions of Appendix E, instead of

CEMS, to determine the NOX emission

rate, stating that this was a de minimis

exception. The EPA allowed this

exception from the requirements of

section 412 of the CAA because the NOX

emissions from these units would be

extremely low, both collectively and

individually (see 58 FR 3644–45). One

utility wrote to the Agency, suggesting

that the Agency consider further

regulatory relief for other units with

extremely low emissions that do not fall

under the categories of small new units

burning fuels with a sulfur content less

than or equal to 0.05 percent by weight

or gas-fired and oil-fired peaking units

(see Docket A–97–35, Item II–D–31).

The utility specifically suggested that

the Agency consider an exemption, the

ability to use Appendix E, or some other

simplified methods which are more cost

effective.

In the process of implementing part

75, other utilities also have suggested to

EPA that it provide regulatory relief to

low mass emitting units (see Docket A–

97–35, Items II–D–29, II–E–25). These

units might be low mass emitting

because they use a clean fuel, such as

natural gas, and/or because they operate

relatively infrequently. Some utilities

stated that they spend a great deal of

time reviewing the emissions data when

preparing quarterly reports for these

units. Others argued that it would be

important to reduce monitoring and

quality assurance (QA) requirements in

order to save time and money currently

devoted to units with minimal

emissions (see Docket A–97–35, Item II–

E–25).

In response to the requests for

simplified monitoring and

recordkeeping requirements for units

which both operate infrequently and

have low mass emissions on May 21,

1998 the Agency proposed, under

§ 75.19 of part 75, changes to the

monitoring requirements that would

allow a new excepted methodology for

low mass emission units. The proposed

low mass emissions methodology would

have allowed units which have

emissions less than 25 tons of both NOX

and SO2 to use a methodology with

reduced monitoring, reporting and

quality assurance requirements than the

use of CEMS or either appendix D or E

methodologies. The methodology

proposed used a unit’s maximum rated

hourly heat input and generic defaults

for SO2, NOX and CO2 mass emissions.

The proposed methodology was a less

accurate methodology for determining

emissions for SO2, NOX and CO2 but

would significantly reduce the burden

on industry for these sources. The

allowance of this methodology was

justified using the de minimis

individual and aggregate emissions

represented by the units who would

qualify for the methodology.

While the proposed methodology did

not contain an explicit cutoff for CO2,

EPA believes that the limited

applicability of the proposal ensured

that emissions of CO2 from units that

would qualify to use the proposal was

also de minimis. This is important,

because under section 821 of the Act,

the agency is also required to collect

CO2 emissions data from sources subject

to title IV. This data is required to be

collected ‘‘in the same manner and to

the same extent’’ as required under title

IV.

The Agency solicited comments on

both the proposed methodology for

determining emissions and the

proposed applicability limits of 25 tons

for both NOX and SO2 as well as any

other comments related to the proposed

low mass emission methodology. In

reviewing the comments submitted on

the proposal, the Agency noted that

several commenters suggested the

methodology was too restrictive and

would only allow reduced monitoring to

a limited number of units. The

commenters suggested various methods

for expanding applicability to the low

mass emission methodology the most

common which are; (i) remove the

requirement for units to have both SO2

and NOX emissions of less than 25 tons

and instead to allow units to use the

methodology on a pollutant specific

basis; (ii) increase the 25 ton limit for

NOX and SO2 to 50, 100 or 250 tons; (iii)

allow additional methods for calculating

heat input; and (iv) allow the use of

unit-specific NOX emission rates. One

other significant comment was received

which indicated that the default values

for NOX emission rate in table 1b of

proposed § 75.19 (c) could significantly

underestimate emissions from certain

types of units.

In response to the comments, which

generally advocating the applicability of

the low mass emissions methodology to

more units, the Agency is adopting the

proposed low mass emissions

methodology with the following

changes: (1) the NOX applicability limit

is being raised to 50 tons which will

increase the number of units that can

use the methodology; (2) units are being

allowed an optional procedure for heat

input which will increase the number of

units that can use the methodology and

provide more accurate emission

estimates; (3) units are being allowed to

use unit-specific NOX emission rates

determined through testing which will

allow increased applicability and more

accurate emissions estimates for NOX;

and (4) the values for NOX emission rate

in table 1b of proposed 75.19 (c) are

being changed to prevent

underestimation of emissions using the

methodology.

B. Discussion of Low Mass Emissions

Methodology

Today’s new Low Mass Emissions

methodology incorporates optional

reduced monitoring, quality assurance,

and reporting requirements into part 75

for units that burn only natural gas or

fuel oil, emit no more than 25 tons of

SO2 and no more than 50 tons of NOX

annually, and have calculated annual
Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations 57485

SO2 and NOX emissions that do not

exceed such limits. Units that are not

subject to Title IV of the Act and that

are only subject to subpart H of part 75

are not required to meet the SO2 limit

to qualify to use the methodology. In

addition, if allowed by their State, they

may qualify as low mass emission units

during the ozone season if they emit less

than 25 tons of NOX per ozone season.

A unit may initially qualify for the

reduced requirements by demonstrating

to the Administrator’s satisfaction that

the unit meets the applicability criteria

in § 75.19(a). Section 75.19(a) requires

facilities to submit historical actual (or

projections, as described below) and

calculated emissions data from the

previous three calendar years

demonstrating that a unit falls below the

25-ton cutoff for SO2 and the 50 ton

cutoff for NOX. The calculated SO2 mass

emissions data for the previous three

calendar years will be determined by

choosing one of the two heat input

options in § 75.19(c) and the appropriate

emission rate from table 1a in § 75.19(c).

The calculated NOX mass emissions

data for the previous three calendar

years will be determined by choosing

one of the two heat input options in

§ 75.19(c) and either the appropriate

emission rate from table 1b in § 75.19(c)

or a unit-specific NOX emission rate as

allowed under § 75.19(c). The data

demonstrating that a unit meets the

applicability requirements of § 75.19(a)

will be submitted in a certification

application for approval by the

Administrator to use the low mass

emissions excepted methodology.

For units that lack historical data for

one or more of the previous three

calendar years (including new units that

lack any historical data), § 75.19(a) will

require the facility to provide (1) any

historical emissions and operating data,

beginning with the unit’s first calendar

year of commercial operation, that

demonstrates that the unit falls under

the 25-ton cutoffs for SO2 and the 50 ton

cutoff for NOX, both with actual

emissions and with calculated

emissions using the proposed

methodology, as described below; and

(2) a demonstration satisfactory to the

Administrator that the unit will

continue to emit below the tonnage

cutoffs (e.g., for a new unit, applying the

applicable emission rates and applicable

hourly heat input, under § 75.19(c), to a

projection of annual operation and fuel

usage to determine the projected mass

emissions).

For units with historical actual (or

projections, as described above)

emissions and calculated emissions

falling below the tonnage cutoffs,

facilities allowed to use the optional

methodology in § 75.19(c) in lieu of

either CEMS or, where applicable, in

lieu of the excepted methods under

Appendix D, E, or G for the purpose of

determining and reporting heat input,

NOX emission rate, and NOX, SO2, and

CO2 mass emissions. The facility will no

longer be required to keep monitoring

equipment installed on low mass

emissions units, nor will it be required

to meet the quality assurance test

requirements or QA/QC program

requirements of Appendix B to part 75.

Moreover, emissions reporting

requirements will be reduced by

requiring only that the facility report the

unit’s hourly mass emissions of SO2,

CO2, and NOX, the fuel type(s) burned

for each hour of operation, and report

the quarterly total and year-to-date

cumulative mass emissions, heat input,

and operating time, in addition to the

unit’s quarterly average and year-to-date

average NOX emission rate for each

quarter. Owners and operators may also

choose to report partial hour operating

time and use the operating time to

obtain a more accurate estimate of heat

input determined using the maximum

hourly heat input option. For units

which use the optional long term fuel

flow methodology for heat input the

source will report hourly and

cumulative quarterly and yearly output

in either megawatts electrical output or

thousands of pounds of steam. For units

which use unit-specific NOX emission

rates determined through testing,

reporting of the Part 75 Appendix E test

results will be required. For units that

have NOX controls, data demonstrating

that these controls are operating

properly will have to be kept on site.

Facilities will continue to be required to

monitor, record, and report opacity data

for oil-fired units, as specified under

§§ 75.14(a), 75.57(f), and 75.64(a)(iii)

respectively. Under § 75.14(c) and (d),

however, gas-fired, diesel-fired, and

dual-fuel reciprocating engine units will

continue to be exempt from opacity

monitoring requirements.

If an initially qualified unit

subsequently burns fuel other than

natural gas or fuel oil, the unit will be

disqualified from using the reduced

requirements starting the first date on

which the fuel (other than natural gas or

fuel oil) burned.

In addition, if an initially qualified

unit subsequently exceeds the 25-ton

cutoff for either SO2 or the 50 ton cutoff

for NOX while using the adopted

methodology, the facility will no longer

be allowed to use the reduced

requirements in § 75.19(c) for

determining the affected unit’s heat

input, NOX emission rate, or SO2, CO2,

and NOX mass emissions (unless at a

future time the unit can again meet the

applicability requirements based on the

recent three years of data). Adopted

§ 75.19(b) allows the facility two

quarters from the end of the quarter in

which the exceedance of the relevant

ton cutoff(s) occurred to install, certify,

and report SO2, CO2, and NOX data from

a monitoring system that meets the

requirements of §§ 75.11, 75.12, and

75.13, respectively.

Under the low mass emission

excepted methodologies in § 75.19(c), a

facility will calculate and report hourly

SO2, NOX and CO2 mass emissions by

multiplying hourly unit heat input by

an appropriate emission rate. Unit heat

input is determined using one of two

heat input methodologies, maximum

rated hourly heat input or long term fuel

flow; unit SO2 and CO2 emission rates

are determined using generic defaults;

and unit NOX emission rate is

determined using one of two

methodologies, generic defaults or unitspecific NOX emission rate testing.

Commenters raised three major issues,

which have led EPA to modify its

proposal. The three major issues raised

were: (i) Should the proposed initial

and ongoing applicability criteria of 25

tons of both NOX and SO2 be modified;

(ii) was the proposed methodology for

estimating emissions appropriate and,

should other options for calculating

emissions be allowed; and (iii) what

should the reduced monitoring and

quality assurance requirements be for

these units?

1. Applicability Criteria

a. Approach. Based on the rationale

described in the preamble to the May

12, 1998 proposal (63 FR 28037) and in

the absence of significant adverse

comment, the Agency is using both

actual and calculated emissions as the

basis for determining initial

applicability.

b. Cutoff Limit for Applicability.

Several commenters requested that the

cutoff limit for applicability of the low

mass emission provision be increased.

These comments fell into two broad

categories: (1) decouple the NOX and

SO2 requirements and allow units

which qualify as a low mass emissions

unit for only one pollutant to monitor

that pollutant using the low mass

emissions methodology (see Docket A–

97–35, Items, IV–D–24, IV–D–11, IV–D–

23, IV–G–03, IV–D–20); and (2) raise the

tonnage cutoff for NOX and SO2 (see

Docket A–97–35, Items, IV–G–03, IV–D–

24, IV–D–22, IV–D–23, IV–D–07, IV–G–

02).

c. Determining the Criteria for Low

Mass Emitters. Based on comments

received the Agency believes that the
57486 Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations

low mass emission provision is

appropriate for units which have low

mass emissions because: (i) a unit has a

low capacity factor usage or operates

infrequently; or (ii) a unit has low mass

emissions despite a relatively high

capacity factor due to the small size of

the unit. For these units, the cost of

installing and maintaining CEMS would

represent a relatively large portion of

the total value of the electricity or steam

produced by the unit. The Agency, also

reasoned that the types of units

identified above can use the excepted

methodology without any significant

risk to the environment or impairment

of the Agency’s ability to meet its

obligations under the CAA.

The Agency also determined the types

of units which were not appropriate

candidates for use of the low mass

emissions excepted methodology. In

particular, the Agency has concerns

about allowing large numbers of

controlled units to use an estimation

methodology such as the low mass

emission methodology. Because many of

these units have low mass emissions not

because they operate infrequently, but

rather because they have controls which

reduce their emission rates, their

continued low mass emissions is

dependent on continued proper

operation of the controls on the unit.

The EPA believes that monitoring actual

emission rates is necessary to ensure

that installed emission controls are

operating properly and that actual

emissions remain low. On the other

hand, EPA believes that it is appropriate

to allow small or infrequently operated

units with controls, such as peaking

turbines with water or fuel injection, to

use the low mass emissions provision.

This is appropriate because as long as

these units continue to limit their

operation, their potential to emit still

remains low, even if their controls are

not working. Therefore, while EPA

believes it is appropriate to allow small

infrequently operated units with

controls that have both low actual

emissions and a low potential to emit

(as long as they continue to operate at

low levels), EPA does not believe that it

is appropriate to allow controlled units

that have large potential to emit if their

controls are not operating properly to

use this methodology.

The low mass emission excepted

methodology is a new exception, in

addition to the exceptions in the

existing rule, from the requirement for

a NOX CEMS. The determination of

whether individual and collective

emissions covered by the exceptions

from CEMS are de minimis must

include consideration of emissions from

both new and existing units that will

qualify to use the new low mass

emissions excepted methodology and

also new and existing units that will

qualify to use other exceptions from the

NOX CEM requirement, i.e. units using

the existing appendix E excepted

methodology and units with new unit

exemptions under § 72.7.

The EPA has first considered the level

of projected aggregate emissions

determined to be de minimis for

purposes of developing the new unit

exemption promulgated in the January

11, 1993 Acid Rain permitting rule (58

FR 3593–94 and 3645–46). Aggregate

emissions projected for units under the

exemption were approximately 138

cumulative tons of SO2 and 1934

cumulative tons of NOX emitted per

year from an estimated 170 new units

which might qualify for the exception

before the year 2000. As of September

of 1998, 278 exemptions have actually

been granted under the new unit

exemption. The Agency estimates that

the level of SO2 and NOX mass

emissions from these units is 226 tons

of NOX and 3163 tons of SO2. The

Agency further believes that this group

of excepted units will continue to

increase at the current rate.

The EPA has also considered the level

of emissions projected to be covered by

appendix E. The EPA, in the January 11,

1993 Acid Rain monitoring rule,

allowed gas-fired and oil-fired peaking

units to use the provisions of appendix

E, instead of CEMS, to determine the

NOX emission rate. The Agency stated

that, even though this method was less

accurate than CEMS, this was a de

minimis exception because emissions

from all units that qualify to use the

appendix E reporting methodology were

projected to be extremely low, the units

did not have a NOX compliance

obligation, and the cost of installing and

operating CEMS for these units would

be high (see 58 FR 3644–45). The

preamble to the January 11, 1993 rule

estimated the emissions from oil and gas

units which operated with a capacity

factor of less than 10 percent to be

40,000 tons of NOX per year. The

Agency has analyzed existing appendix

E units to determine the actual NOX

mass emissions reported by these units

in 1997. This analysis indicates that in

1997 approximately 235 units used the

appendix E methodology and had total

emissions of approximately 11,000 tons

of NOX in 1997. (see Docket A–97–35,

Items, IV–A–1).

The Agency has then considered what

level of total NOX emissions would be

de minimis for all units that may be

covered by de minimis exceptions from

the requirement to use CEMS i.e. all

units using the new unit exemption,

appendix E, and the new low mass

emissions methodology. The Agency

maintains that a de minimis level of

total NOX emissions should not be more

than one percent of the total NOX

emission inventory currently or in the

future for all units. This approach is

supported by the treatment of 40,000

tons of NOX as de minimis in the

January 11, 1993 rule preamble

concerning appendix E, which is

somewhat less than 1 percent of the

total NOX emissions estimated for 1993.

However, the 40,000 tons of NOX

determined to be de minimis emissions

in 1993 is not an appropriate de

minimis level with regard to current and

future levels of NOX emissions. Several

factors have increased the importance of

monitoring lower levels of NOX

emissions including: (i) The new more

stringent NAAQS for ozone (NOX is an

ozone precursor); (ii) title IV Phase II

NOX reductions which will reduce the

total NOX inventory; (iii) today’s NOX

SIP call which may result in NOX

compliance obligations for gas-and oilfired units and will reduce the NOX

emission inventory; and (iv) State and

regional NOX reduction programs, such

as the OTC program, State RACT rules

and the RECLAIM program in

California, which result in NOX

compliance obligations for gas-and oilfired units and reduced NOX emission

inventory. As a result, EPA views about

20,000 tons (close to 1 percent of

projected NOX emission inventory) as

the de minimis level of NOX emissions

for the present and foreseeable future.

Given that appendix E units and new

unit exemption units currently account

for about 14,100 tons of NOX there is not

a large margin left for establishing

additional exception to the CEM

requirements. The Agency has

considered potential future growth in

the number of units using the new unit

exemption or appendix E in order to

estimate what level of additional NOX,

SO2 and CO2 emissions might be

appropriate to allow under the low mass

emissions methodology. Taking account

of the uncertainty inherent in such

estimates EPA has set the applicability

criteria for the low mass emission

methodology so that the NOX emissions

covered by the methodology plus future

growth in NOX emissions covered by the

other current de minimis exceptions

(appendix E and the new unit

exemption) will not exceed 5000 tons of

NOX per year in the future.

The Agency has analyzed SO2, NOX

and CO2 emissions and determined that,

as long as the cutoffs for NOX and SO2

are coupled so that a unit must meet

both the 50 tons of NOX and 25 tons of
Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations 57487

SO2 limits, that SO2, NOX and CO2

emissions under all exceptions from

CEMS requirements will remain de

minimus. Additionally decoupling the

NOX and SO2 tons would allow only

marginal simplification in monitoring

while significantly complicating the low

mass emissions methodology.

d. Determining the Tonnage Cutoffs

for SO2 and NOX. The Agency has

conducted a study of actual emissions

data from 1997 quarterly reports under

part 75 and evaluated potential tonnage

cutoffs for SOX and NOX (see Docket A–

97–35, Item IV–A–1). The analysis was

based on the assumption that reported

1997 emissions of NOX and SO2 will be

more representative of calculated

emissions under the final low mass

emissions methodology than they would

have been under the proposed

methodology. The assumption is

considered valid because the final low

mass emissions methodology allows

more accurate heat input determination

using long term fuel flow and the use of

fuel and unit specific NOX emission

rates. These options allow more

accurate emissions estimates than the

proposed methodology would have.

This differs from the analysis performed

for the proposed low mass emission

methodology which calculated

emissions based on operating hours and

maximum rated heat input.

Based on this analysis, EPA estimates

that the existing Acid Rain affected

sources that would qualify for the low

mass emissions excepted methodology

using a coupled 50 tons NOX and 25

tons SO2 limit would represent

aggregate emissions of approximately

3100 tons of NOX and approximately

260 tons of SO2 in 1997 from 224 units.

The analysis indicates that the

applicability has been substantially

increased in response to the comments

received.

For the proposed 25 ton NOX cutoff ,

which is the limiting factor for

applicability in nearly all instances, the

Agency has considered increasing the

tons of NOX to 50 tons, 75 tons, 100

tons, and 250 tons as suggested by

various commenters. In its analysis, the

Agency kept SO2 at 25 tons, as

discussed above.

The analysis showed that by

increasing the NOX limit to 250 tons

coupled to 25 tons of SO2, the aggregate

tons of NOX and SO2 emitted by units

which could currently qualify for the

low mass emissions methodology

increased to approximately 23124 tons

NOX and 4503 tons of SO2; this is

without considering potential future

growth in the number of units that

could qualify to use this exemption.

Increasing the cutoff for NOX to 250 tons

could also allow many units with highly

effective NOX controls to use the low

mass emissions provision. As explained

previously, units with effective NOX

controls and high operating capacity

should not use the low mass emission

provision. The EPA concludes that with

a 250 ton NOX mass emissions

applicability cutoff, the aggregate NOX

tons and percentage of inventory

potentially covered by all the exceptions

encompassed would easily exceed the

de minimis level of emissions. The EPA

has therefore, not adopted an increased

cutoff limit for NOX of 250 tons.

Similarly, EPA concludes that an

increased cutoff of 100 tons of NOX

would not be consistent with the type

of source which the Agency has

identified for use of the low mass

emission excepted methodology or fit

under the de minimis level of emissions

defined for NOX by the Agency. At the

100 ton cutoff for NOX coupled to a 25

ton cutoff for SO2 the aggregate NOX

emissions are 8841 tons of NOX and 540

tons of SO2 from 408 qualifying units.

The analysis performed by the Agency

indicates that 50 tons of NOX coupled

to 25 tons of SO2 is the appropriate

cutoff limit for applicability to the low

mass emissions excepted methodology.

The approximate aggregate emissions of

3600 tons of NOX and 250 tons of SO2

from 240 sources allows the appropriate

type of units to use the provisions

without great potential of exceeding a

de-minimus level of NOX emissions. In

choosing the 50 ton NOX mass emission

cutoff limit over other limits, the

Agency evaluated the available data and

applied the following criteria: (1) The

NOX tons limit should allow reduced

monitoring for the units which EPA

determined were appropriate candidates

for the low mass emissions provisions

during the rulemaking process, namely

units with low mass emissions both

collectively and individually due to low

operating levels or small size but not

highly controlled units which operate at

higher levels; (2) the NOX tons limit

should allow reduced monitoring for a

group of units consistent with the level

of de minimis emissions inventory for

all exceptions for the CEMS

requirement; and (3) the limit should

not jeopardize the Agency’s ability to

effectively fulfill its obligations under of

the CAA.

From the analysis performed, the

Agency has demonstrated that

increasing the 25 ton limit for SO2

would result in allowing few additional

sources the option to use the low mass

emissions methodology. For example at

a coupled 50 tons of NOX and 25 tons

of SO2 increasing the SO2 tonnage cutoff

to 50 tons would allow only 7

additional units to use the methodology.

The additional units identified all

combusted oil as the primary fuel which

has a very high sulfur content in

comparison to natural gas. While

natural gas fired units could easily

increase operations without substantial

increases in SO2 emissions oil fired

units could not. The additional units

which burn oil and qualify are

considered inappropriate candidates for

use of the low mass emission provision.

Therefore, the Agency has chosen to

leave the tonnage limit at the proposed

level of 25 tons for SO2. Leaving the

cutoff for applicability for SO2 at 25 tons

also reflected the opinion of

commenters who suggested raising only

the NOX tonnage.

When considering the size cutoffs,

EPA also took into account both the

effect that the use of this methodology

could have on other regulatory actions

and the effect that other regulatory

actions could have on the number of

units and percentage of emissions that

could be covered by units using this

methodology. In particular, EPA was

concerned about the SIP call. Units that

could qualify to use the low mass

emission methodology do not have a

NOX emission limit under title IV.

However, under the SIP call, units that

are using the monitoring requirements

of part 75 to comply with the

requirements of the SIP call, including

units that could qualify to use the low

mass emitter methodology, would have

an emission limit. As explained in

Section VI.A.2.c and VII.D.3 of today’s

preamble, EPA believes that it is

important that large sources of NOX

mass emissions accurately account for

their emissions. Because EPA is

expecting substantial reductions in NOX

emissions from the title IV phase II NOX

emission rate limits, the SIP call and

other similar programs, EPA believes

that even if the total NOX emissions

coming from units that could qualify for

the low mass emitter methodology does

not increase, the percentage of

emissions coming from these units will

increase. The EPA also believes that the

incentives provided under a trading

program could encourage smaller oil

and gas fired units that may not

currently qualify under the low mass

emission methodology to install

controls. As a result, this could increase

the number of units, the amount of

emissions and the percentage of

emissions that could be accounted for

by units using this methodology. EPA

believes that the 50 ton cutoff is

adequate to ensure that emissions from

units that qualify for the low mass
57488 Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations

emitter methodology are de-minimis

today. In the future however, growth in

the number of units may cause the level

of NOX, SO2 or CO2 emissions from

units qualifying for and using the new

unit exemption, appendix E, the low

mass emitter provision and other

programs such as the SIP call to exceed

a de-minimis level and the agency

reserves the right to re-assess any and

all of these exceptions in the future if

the need arises.

e. Decoupling NOX and SO2. In order

to qualify for the low mass emissions

excepted methodology, the applicability

criteria require a unit to meet annual

tonnage cutoffs of 25 tons for SO2 and

50 tons for NOX. The EPA has

considered whether the excepted

methodology should be available on a

pollutant specific level so that, for

example, a unit which falls below the

tonnage cutoff for SO2 but not for NOX

could use the excepted methodology

under § 75.19 to measure SO2 emissions

but use a NOX CEM or the excepted

methodology under appendix E, where

applicable, to measure NOX emissions.

All analysis the Agency has done

indicates that the NOX tonnage is the

limiting factor for greater than 90

percent of all units when applicability

is for units to meet a coupled 50 ton

NOX and 25 ton SO2 limit (see Docket

A–97–35, Items, II–A–10, IV–A–1) For

example, approximately 20 units were

identified which would potentially be

qualified to use the low mass emission

methodology for a 50 tons of NOX cutoff

who would not meet the 25 tons of SO2

cutoff and therefore be disqualified from

using the methodology. Conversely, the

agency’s analysis indicated that leaving

the tonnage cutoff for SO2 mass

emissions at 25 tons and decoupling

NOX and SO2 would potentially allow

approximately 650 units in the program

to use the low mass emissions

methodology for SO2 (see Docket A–97–

35, Items, II–A–10, IV–A–1). In

particular allowing decoupling could

impair the Agency’s ability to collect

data on CO2 emissions as required

under the CAA section 821. The

analysis performed by the Agency

indicates, that even with a 25 ton limit

on SO2, 652 units could qualify for the

use of the low mass emissions

methodology for SO2 only. The 652

units identified represent approximately

10 percent of the total program heat

input and greater than 6 percent of the

total program CO2 emissions. If a unit

which qualified for the use of only SO2

were allowed to use the low mass

emissions methodology for CO2 the

result could be overestimation of CO2

emissions from a sizeable percentage of

the total CO2 inventory. Future

decisions based on such data might

draw incorrect conclusions.

For the reason stated above, if a unit

were allowed to qualify for a single

pollutant the unit would be allowed to

use the low mass emissions

methodology for that pollutant only and

not for CO2 or heat input estimations.

Therefore, no practical benefit for

industry would result from decoupling

SO2 and NOX. Decoupling would not be

particularly beneficial because

qualifying for one pollutant only allows

only minimal monitoring reductions

when CO2 and heat input are not

simplified. In addition decoupling

would dramatically increase the

complexity of the low mass emissions

methodology. The added complications

which would benefit a limited number

of sources in only a limited way would

increase the time and effort needed for

all other sources in understanding and

implementing the methodology. The

agency concludes that the burden from

the increased rule complexity outweighs

the benefit from decoupling SO2 and

NOX.

The following discussions further

explain the Agencies position.

One of the prime benefits of the low

mass emissions excepted methodology

will be the simplified reporting which

will require less time and a less

sophisticated Data Acquisition and

Handling System (DAHS). In particular,

the need for a DAHS that could

calculate substitute data using the

current missing data algorithms will be

removed because there are no missing

data algorithms for the low mass

emissions excepted methodology. If the

excepted methodology is only applied

to one of the pollutants, much of the

benefit would be negated because the

DAHS will still need to be capable of

calculating substitute data for the

measured pollutant and close to the full

quarterly report would still be required.

Another prime benefit of the low mass

emissions excepted methodology will be

the reduction of monitoring and quality

assurance requirements. A unit which

would qualify for SO2 only would still

need to determine CO2 mass emissions

using a fuel flow meter. Additionally

the units which would qualify are

primarily gas fired units which would

be allowed to use appendix D for SO2.

In this case no benefit is allowed by

using the low mass emissions

methodology. A limited number of oil

fired units would be granted some

reduced sampling requirements.

The agency’s analysis indicates that

most units which would qualify for NOX

only can use the excepted methodology

under appendix E.

As stated before the analysis indicates

that the benefits of decoupling are

outweighed by the complications of

allowing decoupling.

f. The use of the Low Mass Emitter

Methodology with fuels other than oil

and natural gas. One commenter

suggested that the applicability should

be expanded to include other fuels

including low sulfur solid fuels such as

wood. EPA disagrees with the

commenter who claims that the

methodology should be irrespective of

fuel type. The fuel type is an integral

part of the emissions calculations and

insures that emissions are not

underestimated. The Agency does not

have, and the commenter did not

provide, sufficient data to justify

including wood fired solid fuel units

into the low mass emission

methodology. The limited data EPA has

does not provide assurance that wood is

always low in sulfur or that it results in

low mass emissions of NOX. The use of

AP 42 emission factors was considered

but rejected based on the possibility of

underestimation of NOX emissions

using the AP 42 factors, as stated in the

January 11, 1993 rule preamble at 58 FR

364445. If EPA is provided with

information addressing this issue in the

future, EPA will consider expanding the

applicability to units that burn wood in

the future.

2. Method for Determining Emissions

On May 21, 1998 the Agency

proposed a low mass emissions

methodology which used maximum

rated heat input as the only heat input

option and default emission rates for

SO2, NOX, and CO2. The Agency

requested comment on whether this

methodology was appropriate or

whether an alternate approach should

be adopted for low mass emitting units.

In response, several commenters

suggested changing the method for

determining emissions. One commenter

suggested allowing the use of unitspecific NOX testing (see Docket A–97–

35, Item IV–D–20). Another commenter

suggested that long term fuel flow heat

input be allowed as an alternative to the

proposed maximum rated heat input

(see Docket A–97–35, Item IV–D–13).

Two other commenters suggested that

further unspecified options be allowed

for determining heat input (see Docket

A–97–35, Items, IV–D–03, IV–G–02).

Additionally several commenters

suggested that the reduced monitoring

under the low mass emission

methodology was being limited to too

few sources (see Docket A–97–35, Items,

IV–D–07, IV–D–22, IV–D–23, IV–D–24,

IV–G–03). Other commenters made the

general suggestion that part 75 should
Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations 57489

be more consistent with the monitoring

requirements of the OTC NOX Budget

Program. Finally the Agency received

both comments and data which

indicated that for uncontrolled gas fired

turbines combusting both oil and gas the

default emission rates for NOX in

proposed table 1b of § 75.19 (c) were

potentially substantial underestimations

of actual emission from these types of

units (see Docket A–97–35, Item IV–D–

22). Further analysis by the Agency

provided supporting evidence that the

emission rates in proposed 75.19 (c),

table 1b, might underestimate emissions

significantly for gas and oil fired

turbines (see Docket A–97–35, Item IV–

A–1). In response to these comments

which reflected a general desire to

expand the applicability of the low mass

emission methodology through changes

in both the heat input and NOX

emissions methodology, and in light of

no negative comments reflecting

opposition to allowing the low mass

emission methodology, the Agency

began analysis of what changes in the

methods for determining heat input and

NOX emissions could be allowed

without risk of underestimation of

emissions, or negative environmental

consequences. The Agency received no

comments on changing either the SO2 or

CO2 methods for determining emissions

and therefore did not attempt to change

these methodologies.

a. Adoption of the Proposed

Methodology. In the proposal, the

Agency considered several methods for

determining the estimated emissions as

the basis for applicability of the reduced

monitoring and reporting excepted

methodology. For each of the methods

considered, rather than using actual

measured sulfur and carbon values,

CO2, SO2, and flow CEM readings, NOX

CEM readings, or NOX values from an

Appendix E NOX-versus-heat input

correlation, a facility will calculate the

unit’s emissions based on an emission

rate factor and one of two heat input

methodologies. Since the units that will

qualify for the excepted methodology

will still be accountable for reporting

emissions to the Agency and

surrendering allowances based on those

emissions, where applicable, the

emissions estimations will not just be

used to determine if the unit qualifies

under the exception; the reported

estimations will also be used to

determine compliance. Prior to the

proposal, some industry representatives

suggested that facilities would be

willing to use a conservative emission

estimate, such as a maximum potential

emission rate times the maximum heat

input, if it would allow them to save

time and money currently spent on

monitoring and quality assurance (see

Docket A–97–35, Items II–D–30, II–D–

43, II–D–45, II–E–13, and II–E–25). The

Agency decided it was appropriate to

retain the proposed methodologies of

maximum rated heat input and default

SO2, NOX and CO2 emission rates for the

final rule. It was also decided to allow

increased applicability of the low mass

emissions methodology through

optional unit-specific NOX emission rate

determinations and the use of an

optional heat input methodology (e.g.,

long term fuel flow).

b. Change in Table 1b, Default NOX

Emission Rates. In deciding to retain the

proposed low mass emission

methodology as part of the final rule the

Agency had to consider that some

values for NOX emission rate in

proposed table 1b of § 75.19 (c) had a

high potential for underestimating

emissions in at least some cases. The

Agency acknowledged that increasing

the default NOX emission rates in table

1b of § 75.19 (c) will reduce the number

of units allowed to use the low mass

emissions methodology. Based on the

comments received (see Docket A–97–

35, Item IV–D–20) and to both allow

increased applicability and increase the

default rates to an appropriate level, the

use of NOX testing to determine unitsspecific NOX emission rates will be

allowed as an alternative option to using

the default NOX emission rates in table

1b of § 75.19 (c). Allowing the option of

unit-specific NOX emission rates will

generate more realistic NOX emission

rates than the default NOX emission

rates in table 1b of § 75.19 (c) and will

maintain some of the simplicity of the

NOX mass methodology from the low

mass emissions methodology proposal.

The next issue was deciding which

default NOX emission rates in table 1b

of § 75.19 (c) to raise and what level to

raise the defaults to. As a first

consideration the Agency noted that the

default NOX emission rates in table 1b

of proposed § 75.19 (c) should be

increased to the level at which it will be

highly unlikely that any unit that

performed testing will have a higher

emission rate than the default. In this

case, a source might opt to use a default

which would knowingly underestimate

emissions under certain operating

conditions. Since all of the defaults

used in table 1b of proposed § 75.19 (c)

were based on the 90th percentile it is

very likely that some units would have

a higher emission rate than the NOX

emission rates in table 1b of proposed

75.19 (c). For this reason, all of the NOX

emission rate values in proposed table

1b were increased to a level which will

ensure that units will not have higher

tested emission rates than the default

rates in Table 1b. A commenter

suggested that these provisions be more

consistent with the provisions for the

Ozone Transport Commission (OTC),

NOX Budget Program (see Docket A–97–

35, Item IV–D–13). The default emission

rates the Agency decided to adopt are

the default rates used in the OTC NOX

Budget Program (see Docket A–97–35,

Item II–I–7). In the OTC NOX Budget

Program, units similar in emission

characteristics to those who will qualify

as low mass emission units under

today’s rule have the option of unit

specific testing or unit generic default

OTC NOX emission rates. In the OTC

NOX Budget Program units have chosen

both options based on owner or operator

preference. Finally, adopting the NOX

Budget Program defaults creates

consistency among programs which is a

supplementary benefit.

c. Unit-Specific NOX Emission Rate

Testing. In considering the options for

unit-specific NOX emission rate testing

the Agency had to address several

concerns, including the following: (1)

Units with NOX controls who performed

unit specific testing with the controls

operating might have the potential to

grossly underestimate emissions if the

controls failed; (2) what sort of test

would be appropriate for determining

the low mass emissions methodology

fuel -and-unit-specific NOX emission

rate; (3) how long a period should a

source be allowed to use the unitspecific NOX rate once determined

through testing; (4) under what

conditions should a source be required

to retest for a new unit-specific NOX

emission rate; (5) for sources with

historical reported emissions data using

CEMS under part 75, what historical

NOX emission rate value might be

appropriate for use in lieu of an initial

test; and (6) if a source owns multiple

identical units, should representative

testing be allowed at some of the units

to represent all units.

The first issue resolved was the use of

Appendix E of Part 75 procedures for

determination of a unit-specific NOX

emission rate for each fuel combusted

by the unit. The unit-specific NOX

emission rate selected, for each fuel

tested, will be the highest recorded NOX

emission rate from the test at any test

load or operating condition multiplied

by 1.15. Units which combust multiple

fuels can use, for different fuels, either

a unit-specific NOX rate determined

through testing or use the default NOX

emission rates listed in table 1b of

§ 75.19 (c). For example, a unit which

primarily combusts oil but occasionally

combusts natural gas could determine a

unit-specific NOX emission rate for oil
57490 Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations

through Appendix E testing and use the

default NOX emission rate from table 1b

of § 75.19 (c) for gas. For hours in which

a unit combusts multiple fuels in one

hour, the unit must use the highest

emission rate for that hour for all fuels

combusted. In conducting the Appendix

E test, the requirement for monitoring

heat input to the unit during the test is

removed as it is an unnecessary burden.

The multiplier of 1.15 is required

because of Agency analysis which

indicates that appendix E testing is not

representative of emissions at a given

load at all times. In particular, the

analysis of units with NOX emission rate

CEMS indicated that the NOX emission

rate can vary an average of 15 percent

at a given load during different periods

of operation. The most probable cause of

the difference noted is variations in

atmospheric moisture content. The

agency notes that units which do

appendix E testing during hot humid

conditions would likely underestimate

emissions during cooler less humid

conditions. The Appendix E test was

chosen for several reasons including: (1)

many current Acid Rain sources which

might qualify for the low mass

emissions methodology already have

performed Appendix E testing and will

be allowed to use their historical

Appendix E test data to determine a

unit-specific NOX emission rate without

further requirements; (2) the

requirements of Appendix E testing are

already familiar to sources and

contractors who may perform the

testing, thus reducing further burden

imposed by requiring new testing

methodologies; (3) The use of the

Appendix E test and the multiplier of

1.15 ensures that a unit uses a NOX

emission rate which will not

underestimate emissions at any normal

operating condition.

Once the Appendix E test was chosen,

the use of a five year testing frequency

was deemed appropriate as it matched

the current Appendix E test period and

matches the current permit renewal

cycle.

A special provision was included in

the low mass emission methodology to

allow units with historical CEMS NOX

emission rate data to determine a unitspecific NOX emission rate from

historical certified CEMS data. Under

this provision a unit will analyze

historical data from hours in which a

unit combusted a particular fuel. The

analysis will determine the unit-specific

NOX emission rate which will yield a 95

percent confidence that the unit will not

emit at a higher NOX emission rate

while combusting the fuel being

analyzed. The Agency also considered

using the highest NOX rate from

historical data but reasoned that the

large data sets used to generate the unitand fuel-specific emission rate would

contain outliers which would make the

procedure unfeasible for most units. The

Agency considered several options for

units which used NOX controls and

wished to use unit-specific NOX

emission rates determined through

Appendix E testing. One option was to

allow units to test with the NOX control

devices not operating or minimized.

This option was rejected for the

following two reasons: (1) the Agency

does not support adopting a rule which

would require sources to operate in a

manner that would increase emissions;

and (2) some sources which have

controls are not allowed to operate

when the controls are not operating by

permit restrictions and these units

would be disallowed from using the low

mass emission methodology unfairly.

The Agency also considered not

allowing units with NOX emission

controls to use the low mass emission

methodology. While the Agency does

believe that it is not appropriate to

include large controlled units, the

Agency does feel it is appropriate to

allow infrequently used controlled

units, such as peaking turbines with

steam or water injection to benefit from

the reduced requirements of this

methodology (as further explained

above). Therefore this solution was

rejected as excluding many units for

which the Agency believes it is

appropriate to allow reduced

monitoring from more accurate and

more costly monitoring requirements.

The Agency also considered allowing

only units with certain types of controls

to use the low mass emission

methodology. This approach was

rejected because the Agency does not, at

this time, have the necessary

information or expertise to make an

appropriate determination on this

approach.

The Agency also considered allowing

units to determine a unit-specific NOX

emission rate using NOX controls with

no restriction. In analyzing this option,

the Agency identified several units

which would qualify for the low mass

emission methodology based on the

applicability criteria of 50 tons of NOX

and 25 tons of SO2 which the Agency

did not believe were appropriate to use

the low mass emission methodology.

The units identified had advanced

control technologies such as selective

catalytic reduction (SCR) and burned

low sulfur fuels such as natural gas. The

units identified consistently reported

hourly emission rates as low as 0.01 lb/

mmBtu as compared to uncontrolled

rates which are generally 10 to 100

times higher for these units. The best

method of continued assurance that a

unit’s NOX controls are operating is

monitoring with a NOX CEMS. These

units also operated during more than

half the hours of a year at an average

heat input of greater than 1000 mmBtu/

hr. While, for these units, the potential

to underestimate SO2 emissions was

low, the potential to grossly

underestimate NOX mass emissions

using the low mass emission

methodology was much greater. For this

reason, the Agency rejected allowing a

controlled unit to use a single emission

rate determined through Appendix E

testing once every five years while NOX

controls were operating.

The methodology the Agency adopted

in this rule was the use of a lower limit

of 0.15 lb/mmBtu for a unit-specific

NOX emission rate for units which opt

to perform unit-and fuel-specific

Appendix E testing while controls are

operating. For units with NOX emission

controls, which perform unit-specific

NOX emission rate testing and whose

test results in a NOX emission rate of

less than 0.15 lb/mmBtu, the source will

use the NOX emission rate limit of 0.15

lb/mmBtu for the unit-specific NOX

emission rate instead of the lower tested

NOX emission rate. Units with NOX

emission controls who perform unitspecific NOX emission rate testing and

whose results from the testing indicate

a NOX emission rate of higher than 0.15

lb/mmBtu will be required to use the

higher NOX emission rate as the fueland unit-specific NOX emission rate. In

considering this approach the Agency

considered using the lowest NOX

emission rate proposed in 75.19 (c),

Table 1b, of 0.172 lb/mmBtu, as well as

0.15 lb/mmBtu, 0.1 lb/mmBtu and 0.05

lb/mmBtu as lower limits for NOX

emission rate. The proposed gas fired

turbine emission rate was 0.172 lb/

mmBtu. Using 0.172 lb/mmBtu as the

lower limit for controlled units was

rejected as being an arbitrary choice

based on a number representative of

only a single class of units and not

representative of the difference between

controlled and uncontrolled units. An

analysis was performed to determine a

reasonable lower cutoff between

controlled and uncontrolled units

which would allow controlled units to

qualify for the reduced monitoring

provisions of the excepted low mass

emission methodology without serious

risk of underestimation of emissions.

The analysis indicated that a minimum

allowable emission rate of 0.15 lb/

mmBtu for controlled units best allowed

for fairness between controlled and

uncontrolled units and insured that very
Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations 57491

large units with high operating hours

and extremely low NOX emission rates

will not be allowed to use the low mass

emission excepted methodology. The

Agency’s decision was also heavily

influenced by the desire to insure that

overall, the emission rate chosen would

insure that aggregate emissions of

controlled units were indeed de

minimis. The Agency notes that the

lower limit of 0.15 lb/mmBtu NOX

emission rate, when coupled with the

annual limit of 50 tons of NOX,

effectively limits the annual heat input

of units using the methodology to

666,666 mmBtu annual heat input.

Analysis done by EPA found this to be

an appropriate limit on heat input for

the low mass emission excepted

methodology (see Docket A–97–35, Item

IV–D–20). In general, the lower

emission rate limit for controlled units,

and uncontrolled units inability to

achieve such low rates, combines to

limit the low mass emission

methodology to the infrequently

operated low mass emitting units the

Agency was targeting for use of the

provision in today’s new rule.

Controlled units that use this

methodology are also subject to

additional requirements. The owner or

operator of the unit must ensure that the

controls are being operated in the same

manner that they were operated during

the unit specific testing. Documentation

of this must be kept on site. Any hour

that the controls are not operating

properly, the owner or operator must

use the default emission rates for NOX

in table 1.b of § 75.19 (c), rather than the

emission rate determined through unit

specific testing.

Based on experience gained working

with the OTC in the implementation of

the OTC NOX budget program, EPA

believes that many of the units that may

benefit from this new excepted

monitoring methodology are banks of

identical small emission turbines. The

OTC has allowed these units to do

representative sampling at a number of

units rather than requiring testing at all

of the units. While none of the

commenters mentioned this specific

flexibility of the OTC NOX Budget

program, EPA believes that this is one

of the flexibilities that commenters who

suggested adopting some of the

methodologies that the OTC has allowed

for smaller units were referring to.

Therefore this final rule contains a

similar allowance for identical units. If

the owner or operator of a number of

units that are located at one facility can

demonstrate that those units are

identical, this final rule will allow

emission rate testing to be done at a

representative number of units.

d. The Adoption of Maximum Rated

Heat Input as Proposed. While several

commenters suggested allowing

alternative methods for determining

heat input, none directly suggested

replacing or altering the basic heat input

approach as an option (as described in

68 FR 28037–8). For this reason the

maximum rated hourly heat input

option from the proposal was retained

as a less accurate but acceptable

approach.

e. Long Term Fuel Flow for Heat Input

Determination. To allow greater

flexibility to units under the low mass

emissions methodology and to allow

more realistic estimations of heat input

as suggested by several commenters the

Agency is allowing the use of long term

fuel flow measurements to determine

heat input to low mass emitting units as

described earlier. The Agency chose to

adopt this methodology for the

following reasons: (1) The methodology

allows more accurate measurements of

total heat input into a unit over the

reporting period than the use of

maximum rated hourly heat input; (2)

the methodology has proven to be

usable by sources who have chosen to

use a similar method in the Ozone

Transport Commission, NOX Budget

Program; and (3) the methodology is

straightforward and is optional for

sources which might be excluded from

using the low mass emissions

methodology if allowed to use

maximum rated hourly heat input only.

3. Reduced Monitoring and Quality

Assurance Requirements. As discussed

above, today’s rule allows facilities to

use a maximum rated hourly heat input

value and an emission rate factor to

determine the mass emissions from a

low-emitting unit for each hour of actual

operation. This approach involves no

actual emissions monitoring and

minimal quality assurance activities.

Instead, the facility will only need to

keep track of whether the unit

combusted any fuel for a particular hour

and what type of fuel was combusted.

In this way, the revised rule

significantly reduces the burden on

affected facilities, while still ensuring

that emissions are not under reported.

For owners or operators which opt to

use either the long term fuel flow

methodology or a fuel-and unit-specific

NOX emission rate, some additional

quality assurance will be required. As

these two options under the low mass

emission methodology are not required

and will allow units which would not

otherwise qualify to use the low mass

emission methodology, the additional

quality assurance requirements are not

burdensome to the sources using either

long term fuel flow or unit-specific NOX

emission rates.

For the reasons set forth in the

preamble, parts 51, 72, 75, and 96 of

chapter I of title 40 of the Code of

Federal Regulations are amended as

follows:

PART 51—REQUIREMENTS FOR

PREPARATION, ADOPTION, AND

SUBMITTAL OF IMPLEMENTATION

PLANS

1. The authority citation for part 51

continues to read as follows:

Authority: 42 U.S.C. 7401–7671q.

Subpart G—Control Strategy

2. Subpart G is amended to add

§§ 51.121 and 51.122 to read as follows:

§ 51.121 Findings and requirements for

submission of State implementation plan

revisions relating to emissions of oxides of

nitrogen.

(a)(1) The Administrator finds that the

State implementation plan (SIP) for each

jurisdiction listed in paragraph (c) of

this section is substantially inadequate

to comply with the requirements of

section 110(a)(2)(D)(i)(I) of the Clean Air

Act (CAA), 42 U.S.C. 7410(a)(2)(D)(i)(I),

because the SIP does not include

adequate provisions to prohibit sources

and other activities from emitting

nitrogen oxides (‘‘NOX’’) in amounts

that will contribute significantly to

nonattainment in one or more other

States with respect to the 1-hour ozone

national ambient air quality standards

(NAAQS). Each of the jurisdictions

listed in paragraph (c) of this section

must submit to EPA a SIP revision that

cures the inadequacy.

(2) Under section 110(a)(1) of the

CAA, 42 U.S.C. 7410(a)(1), the

Administrator determines that each

jurisdiction listed in paragraph (c) of

this section must submit a SIP revision

to comply with the requirements of

section 110(a)(2)(D)(i)(I), 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 8-hour ozone

NAAQS.

(b)(1) For each jurisdiction listed in

paragraph (c) of this section, the SIP

revision required under paragraph (a) of

this section will contain adequate

provisions, for purposes of complying

with section 110(a)(2)(D)(i)(I) of the

CAA, 42 U.S.C. 7410(a)(2)(D)(i)(I), only

if the SIP revision:
57492 Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations

(i) Contains control measures

adequate to prohibit emissions of NOX

that would otherwise be projected, in

accordance with paragraph (g) of this

section, to cause the jurisdiction’s

overall NOX emissions to be in excess of

the budget for that jurisdiction

described in paragraph (e) of this

section (except as provided in paragraph

(b)(2) of this section),

(ii) Requires full implementation of

all such control measures by no later

than May 1, 2003, and

(iii) Meets the other requirements of

this section. The SIP revision’s

compliance with the requirement of

paragraph (b)(1)(i) of this section shall

be considered compliance with the

jurisdiction’s budget for purposes of this

section.

(2) The requirements of paragraph

(b)(1)(i) of this section shall be deemed

satisfied, for the portion of the budget

covered by an interstate trading

program, if the SIP revision:

(i) Contains provisions for an

interstate trading program that EPA

determines will, in conjunction with

interstate trading programs for one or

more other jurisdictions, prohibit NOX

emissions in excess of the sum of the

portion of the budgets covered by the

trading programs for those jurisdictions;

and

(ii) Conforms to the following criteria:

(A) Emissions reductions used to

demonstrate compliance with the

revision must occur during the ozone

season.

(B) Emissions reductions occurring

prior to the year 2003 may be used by

a source to demonstrate compliance

with the SIP revision for the 2003 and

2004 ozone seasons, provided the SIP’s

provisions regarding such use comply

with the requirements of paragraph

(e)(3) of this section.

(C) Emissions reduction credits or

emissions allowances held by a source

or other person following the 2003

ozone season or any ozone season

thereafter that are not required to

demonstrate compliance with the SIP

for the relevant ozone season may be

banked and used to demonstrate

compliance with the SIP in a

subsequent ozone season.

(D) Early reductions created according

to the provisions in paragraph

(b)(2)(ii)(B) of this section and used in

the 2003 ozone season are not subject to

the flow control provisions set forth in

paragraph (b)(2)(ii)(E) of this section.

(E) Starting with the 2004 ozone

season, the SIP shall include provisions

to limit the use of banked emissions

reduction credits or emissions

allowances beyond a predetermined

amount as calculated by one of the

following approaches:

(1) Following the determination of

compliance after each ozone season, if

the total number of emissions reduction

credits or banked allowances held by

sources or other persons subject to the

trading program exceeds 10 percent of

the sum of the allowable ozone season

NOX emissions for all sources subject to

the trading program, then all banked

allowances used for compliance for the

following ozone season shall be subject

to the following:

(i) A ratio will be established

according to the following formula:

(0.10) × (the sum of the allowable ozone

season NOX emissions for all sources

subject to the trading program) ÷ (the

total number of banked emissions

reduction credits or emissions

allowances held by all sources or other

persons subject to the trading program).

(ii) The ratio, determined using the

formula specified in paragraph

(b)(2)(ii)(E)(1)(i) of this section, will be

multiplied by the number of banked

emissions reduction credits or

emissions allowances held in each

account at the time of compliance

determination. The resulting product is

the number of banked emissions

reduction credits or emissions

allowances in the account which can be

used in the current year’s ozone season

at a rate of 1 credit or allowance for

every 1 ton of emissions. The SIP shall

specify that banked emissions reduction

credits or emissions allowances in

excess of the resulting product either

may not be used for compliance, or may

only be used for compliance at a rate no

less than 2 credits or allowances for

every 1 ton of emissions.

(2) At the time of compliance

determination for each ozone season, if

the total number of banked emissions

reduction credits or emissions

allowances held by a source subject to

the trading program exceeds 10 percent

of the source’s allowable ozone season

NOX emissions, all banked emissions

reduction credits or emissions

allowances used for compliance in such

ozone season by the source shall be

subject to the following:

(i) The source may use an amount of

banked emissions reduction credits or

emissions allowances not greater than

10 percent of the source’s allowable

ozone season NOX emissions for

compliance at a rate of 1 credit or

allowance for every 1 ton of emissions.

(ii) The SIP shall specify that banked

emissions reduction credits or

emissions allowances in excess of 10

percent of the source’s allowable ozone

season NOX emissions may not be used

for compliance, or may only be used for

compliance at a rate no less than 2

credits or allowances for every 1 ton of

emissions.

(c) The following jurisdictions

(hereinafter referred to as ‘‘States’’) are

subject to the requirements of this

section: Alabama, Connecticut,

Delaware, Georgia, Illinois, Indiana,

Kentucky, Maryland, Massachusetts,

Michigan, Missouri, New Jersey, New

York, North Carolina, Ohio,

Pennsylvania, Rhode Island, South

Carolina, Tennessee, 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

September 30, 1999.

(2) The State makes an official

submission of its SIP revision to EPA

only when:

(i) The submission conforms to the

requirements of appendix V to this part;

and

(ii) The State delivers five copies of

the plan to the appropriate Regional

Office, with a letter giving notice of

such action.

(e)(1) The NOX budget for a State

listed in paragraph (c) of this section is

defined as the total amount of NOX

emissions from all sources in that State,

as indicated in paragraph (e)(2) of this

section with respect to that State, which

the State must demonstrate that it will

not exceed in the 2007 ozone season

pursuant to paragraph (g)(1) of this

section.

(2) The State-by-State amounts of the

NOX budget, expressed in tons, are as

follows:

State Budget

Alabama .................................... 158,677

Connecticut ............................... 40,573

Delaware ................................... 18,523

District of Columbia .................. 6,792

Georgia ..................................... 177,381

Illinois ........................................ 210,210

Indiana ...................................... 202,584

Kentucky ................................... 155,698

Maryland ................................... 71,388

Massachusetts .......................... 78,168

Michigan .................................... 212,199

Missouri ..................................... 114,532

New Jersey ............................... 97,034

New York .................................. 179,769

North Carolina ........................... 151,847

Ohio .......................................... 239,898

Pennsylvania ............................. 252,447

Rhode Island ............................. 8,313

South Carolina .......................... 109,425

Tennessee ................................ 182,476

Virginia ...................................... 155,718

West Virginia ............................. 92,920

Wisconsin .................................. 106,540

Total ................................... 3,023,113
Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations 57493

(3)(i) Notwithstanding the State’s

obligation to comply with the budgets

set forth in paragraph (e)(2) of this

section, a SIP revision may allow

sources required by the revision to

implement NOX emission control

measures by May 1, 2003 to demonstrate

compliance in the 2003 and 2004 ozone

seasons using credit issued from the

State’s compliance supplement pool, as

set forth in paragraph (e)(3)(iii) of this

section.

(ii) A source may not use credit from

the compliance supplement pool to

demonstrate compliance after the 2004

ozone season.

(iii) The State-by-State amounts of the

compliance supplement pool are as

follows:

State

Compliance

supplement

pool (tons

of NOX)

Alabama .................................... 10,361

Connecticut ............................... 559

Delaware ................................... 417

District of Columbia .................. 0

Georgia ..................................... 10,919

Illinois ........................................ 17,455

Indiana ...................................... 19,738

Kentucky ................................... 13,018

Maryland ................................... 3,662

Massachusetts .......................... 285

Michigan .................................... 15,359

Missouri ..................................... 10,469

New Jersey ............................... 1,722

New York .................................. 1,831

North Carolina ........................... 10,624

Ohio .......................................... 22,947

Pennsylvania ............................. 13,716

Rhode Island ............................. 0

South Carolina .......................... 5,062

Tennessee ................................ 12,093

Virginia ...................................... 6,108

West Virginia ............................. 16,937

Wisconsin .................................. 6,717

Total ................................... 200,000

(iv) The SIP revision may provide for

the distribution of the compliance

supplement pool to sources that are

required to implement control measures

using one or both of the following two

mechanisms:

(A) The State may issue some or all

of the compliance supplement pool to

sources that implement emissions

reductions during the ozone season

beyond all applicable requirements in

years prior to the year 2003 according to

the following provisions:

(1) The State shall complete the

issuance process by no later than May

1, 2003.

(2) The emissions reduction may not

be required by the State’s SIP or be

otherwise required by the CAA.

(3) The emissions reduction must be

verified by the source as actually having

occurred during an ozone season

between September 30, 1999 and May 1,

2003.

(4) The emissions reduction must be

quantified according to procedures set

forth in the SIP revision and approved

by EPA. Emissions reductions

implemented by sources serving electric

generators with a nameplate capacity

greater than 25 MWe, or boilers,

combustion turbines or combined cycle

units with a maximum design heat

input greater than 250 mmBtu/hr, must

be quantified according to the

requirements in paragraph (i)(4) of this

section.

(5) If the SIP revision contains

approved provisions for an emissions

trading program, sources that receive

credit according to the requirements of

this paragraph may trade the credit to

other sources or persons according to

the provisions in the trading program.

(B) The State may issue some or all of

the compliance supplement pool to

sources that demonstrate a need for an

extension of the May 1, 2003

compliance deadline according to the

following provisions:

(1) The State shall initiate the

issuance process by the later date of

September 30, 2002 or after the State

issues credit according to the

procedures in paragraph (e)(3)(iv)(A) of

this section.

(2) The State shall complete the

issuance process by no later than May

1, 2003.

(3) The State shall issue credit to a

source only if the source demonstrates

the following:

(i) For a source used to generate

electricity, compliance with the SIP

revision’s applicable control measures

by May 1, 2003, would create undue

risk for the reliability of the electricity

supply. This demonstration must

include a showing that it would not be

feasible to import electricity from other

electricity generation systems during the

installation of control technologies

necessary to comply with the SIP

revision.

(ii) For a source not used to generate

electricity, compliance with the SIP

revision’s applicable control measures

by May 1, 2003, would create undue

risk for the source or its associated

industry to a degree that is comparable

to the risk described in paragraph

(e)(3)(iv)(B)(3)(i) of this section.

(iii) For a source subject to an

approved SIP revision that allows for

early reduction credits in accordance

with paragraph (e)(3)(iv)(A) of this

section, it was not possible for the

source to comply with applicable

control measures by generating early

reduction credits or acquiring early

reduction credits from other sources.

(iv) For a source subject to an

approved emissions trading program, it

was not possible to comply with

applicable control measures by

acquiring sufficient credit from other

sources or persons subject to the

emissions trading program.

(4) The State shall ensure the public

an opportunity, through a public

hearing process, to comment on the

appropriateness of allocating

compliance supplement pool credits to

a source under paragraph (e)(3)(iv)(B) of

this section.

(4) If, no later than November 23,

1998, any member of the public requests

revisions to the source-specific data

used to establish the State budgets set

forth in paragraph (e)(2) of this section

or the 2007 baseline sub-inventory

information set forth in paragraph

(g)(2)(ii) of this section, then EPA will

act on that request no later than January

22, 1999, provided:

(i) The request is submitted in

electronic format;

(ii) Information is provided to

corroborate and justify the need for the

requested modification;

(iii) The request includes the

following data information regarding

any electricity-generating source at

issue:

(A) Federal Information Placement

System (FIPS) State Code;

(B) FIPS County Code;

(C) Plant name;

(D) Plant ID numbers (ORIS code

preferred, State agency tracking number

also or otherwise);

(E) Unit ID numbers (a unit is a boiler

or other combustion device);

(F) Unit type;

(G) Primary fuel on a heat input basis;

(H) Maximum rated heat input

capacity of unit;

(I) Nameplate capacity of the largest

generator the unit serves;

(J) Ozone season heat inputs for the

years 1995 and 1996;

(K) 1996 (or most recent) average NOX

rate for the ozone season;

(L) Latitude and longitude

coordinates;

(M) Stack parameter information ;

(N) Operating parameter information;

(o) Identification of specific change to

the inventory; and

(p) Reason for the change;

(iv) The request includes the

following data information regarding

any non-electricity generating point

source at issue:

(A) FIPS State Code;

(B) FIPS County Code;

(C) Plant name;

(D) Facility primary standard

industrial classification code (SIC);
57494 Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations

(E) Plant ID numbers (NEDS, AIRS/

AFS, and State agency tracking number

also or otherwise);

(F) Unit ID numbers (a unit is a boiler

or other combustion device);

(G) Primary source classification code

(SCC);

(H) Maximum rated heat input

capacity of unit;

(I) 1995 ozone season or typical ozone

season daily NOX emissions;

(J) 1995 existing NOX control

efficiency;

(K) Latitude and longitude

coordinates;

(L) Stack parameter information;

(M) Operating parameter information;

(N) Identification of specific change to

the inventory; and

(O) Reason for the change;

(v) The request includes the following

data information regarding any

stationary area source or nonroad

mobile source at issue:

(A) FIPS State Code;

(B) FIPS County Code;

(C) Primary source classification code

(SCC);

(D) 1995 ozone season or typical

ozone season daily NOX emissions;

(E) 1995 existing NOX control

efficiency;

(F) Identification of specific change to

the inventory; and

(G) Reason for the change;

(vi) The request includes the

following data information regarding

any highway mobile source at issue:

(A) FIPS State Code;

(B) FIPS County Code;

(C) Primary source classification code

(SCC) or vehicle type;

(D) 1995 ozone season or typical

ozone season daily vehicle miles

traveled (VMT);

(E) 1995 existing NOX control

programs;

(F) identification of specific change to

the inventory; and

(G) reason for the change.

(f) Each SIP revision must set forth

control measures to meet the NOX

budget in accordance with paragraph

(b)(1)(i) of this section, which include

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) Should a State elect to impose

control measures on fossil fuel-fired

NOX sources serving electric generators

with a nameplate capacity greater than

25 MWe or boilers, combustion turbines

or combined cycle units with a

maximum design heat input greater than

250 mmBtu/hr as a means of meeting its

NOX budget, then those measures must:

(i)(A) Impose a NOX mass emissions

cap on each source;

(B) Impose a NOX emissions rate limit

on each source and assume maximum

operating capacity for every such source

for purposes of estimating mass NOX

emissions; or

(C) Impose any other regulatory

requirement which the State has

demonstrated to EPA provides

equivalent or greater assurance than

options in paragraphs (f)(2)(i)(A) or

(f)(2)(i)(B) of this section that the State

will comply with its NOX budget in the

2007 ozone season; and

(ii) Impose enforceable mechanisms to

assure that collectively all such sources,

including new or modified units, will

not exceed in the 2007 ozone season the

total NOX emissions projected for such

sources by the State pursuant to

paragraph (g) of this section.

(3) For purposes of paragraph (f)(2) of

this section, the term ‘‘fossil fuel-fired’’

means, with regard to a NOX source:

(i) The combustion of fossil fuel,

alone or in combination with any other

fuel, where fossil fuel actually

combusted comprises more than 50

percent of the annual heat input on a

Btu basis during any year starting in

1995 or, if a NOX source had no heat

input starting in 1995, during the last

year of operation of the NOX source

prior to 1995; or

(ii) The combustion of fossil fuel,

alone or in combination with any other

fuel, where fossil fuel is projected to

comprise more than 50 percent of the

annual heat input on a Btu basis during

any year; provided that the NOX source

shall be ‘‘fossil fuel-fired’’ as of the date,

during such year, on which the NOX

source begins combusting fossil fuel.

(g)(1) Each SIP revision must

demonstrate that the control measures

contained in it are adequate to provide

for the timely compliance with the

State’s NOX budget during the 2007

ozone season.

(2) The demonstration must include

the following:

(i) Each revision must contain a

detailed baseline inventory of NOX mass

emissions from the following sources in

the year 2007, absent the control

measures specified in the SIP

submission: electric generating units

(EGU), non-electric generating units

(non-EGU), area, nonroad and highway

sources. The State must use the same

baseline emissions inventory that EPA

used in calculating the State’s NOX

budget, as set forth for the State in

paragraph (g)(2)(ii) of this section,

except that EPA may direct the State to

use different baseline inventory

information if the State fails to certify

that it has implemented all of the

control measures assumed in

developing the baseline inventory.

(ii) The base year 2007 NOX emissions

sub-inventories for each State,

expressed in tons per ozone season, are

as follows:

State EGU Non-EGU Area Nonroad Highway Total

Alabama .................................................... 76,900 49,781 25,225 16,594 50,111 218,610

Connecticut ............................................... 5,600 5,273 4,588 9,584 18,762 43,807

Delaware ................................................... 5,800 1,781 963 4,261 8,131 20,936

District of Columbia ................................... 1 0 310 741 3,470 2,082 6,603

Georgia ..................................................... 86,500 33,939 11,902 21,588 86,611 240,540

Illinois ........................................................ 119,300 55,721 7,822 47,035 81,297 311,174

Indiana ...................................................... 136,800 71,270 25,544 22,445 60,694 316,753

Kentucky ................................................... 107,800 18,956 38,773 19,627 45,841 230,997

Maryland ................................................... 32,600 10,982 4,105 17,249 27,634 92,570

Massachusetts .......................................... 16,500 9,943 10,090 18,911 24,371] 79,815

Michigan .................................................... 86,600 79,034 28,128 23,495 83,784 301,042

Missouri ..................................................... 82,100 13,433 6,603 17,723 55,230 175,089

New Jersey ............................................... 18,400 22,228 11,098 21,163 34,106 106,995

New York .................................................. 39,200 25,791 15,587 29,260 80,521 190,358

North Carolina ........................................... 84,800 34,027 10,651 17,799 66,019 213,296

Ohio ........................................................... 163,100 53,241 19,425 37,781 99,079 372,626

Pennsylvania ............................................. 123,100 73,748 17,103 25,554 92,280 331,785
Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations 57495

State EGU Non-EGU Area Nonroad Highway Total

Rhode Island ............................................. 1,100 327 420 2,073 4,375 8,295

South Carolina .......................................... 36,300 34,740 8,359 11,903 47,404 138,706

Tennessee ................................................ 70,900 60,004 11,990 44,567 64,965 252,426

Virginia ...................................................... 40,900 39,765 18,622 21,551 70,212 191,050

West Virginia ............................................. 115,500 40,192 4,790 10,220 20,185 190,887

Wisconsin .................................................. 52,000 22,796 8,160 12,965 49,470 145,391

Total ............................................... 1,501,800 757,281 290,689 456,818 1,173,163 4,179,751

1The base case for the District of Columbia is actually projected to be 30 tons per season. The base case values in this table are rounded to

the nearest 100 tons.

(iii) Each revision must contain a

summary of NOX mass emissions in

2007 projected to result from

implementation of each of the control

measures specified in the SIP

submission and from all NOX sources

together following implementation of all

such control measures, compared to the

baseline 2007 NOX emissions inventory

for the State described in paragraph

(g)(2)(i) of this section. The State must

provide EPA with a summary of the

computations, assumptions, and

judgments used to determine the degree

of reduction in projected 2007 NOX

emissions that will be achieved from the

implementation of the new control

measures compared to the baseline

emissions inventory.

(iv) Each revision must identify the

sources of the data used in the

projection of emissions.

(h) Each revision must comply with

§ 51.116 of this part (regarding data

availability).

(i) Each revision must provide for

monitoring the status of compliance

with any control measures adopted to

meet the NOX budget. 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 of this part (regarding testing,

inspection, enforcement, and

complaints);

(3) If the revision contains any

transportation control measures, then

the revision must comply with § 51.213

of this part (regarding transportation

control measures);

(4) If the revision contains measures

to control fossil fuel-fired NOX sources

serving electric generators with a

nameplate capacity greater than 25

MWe or boilers, combustion turbines or

combined cycle units with a maximum

design heat input greater than 250

mmBtu/hr, then the revision must

require such sources to comply with the

monitoring provisions of part 75,

subpart H.

(5) For purposes of paragraph (i)(4) of

this section, the term ‘‘fossil fuel-fired’’

means, with regard to a NOX source:

(i) The combustion of fossil fuel,

alone or in combination with any other

fuel, where fossil fuel actually

combusted comprises more than 50

percent of the annual heat input on a

Btu basis during any year starting in

1995 or, if a NOX source had no heat

input starting in 1995, during the last

year of operation of the NOX source

prior to 1995; or

(ii) The combustion of fossil fuel,

alone or in combination with any other

fuel, where fossil fuel is projected to

comprise more than 50 percent of the

annual heat input on a Btu basis during

any year, provided that the NOX source

shall be ‘‘fossil fuel-fired’’ as of the date,

during such year, on which the NOX

source begins combusting fossil fuel.

(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 NOX budget

specified in paragraph (e) of this

section;

(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;

(4) 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; also

authority for the State to make such data

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 section 114 of the

CAA.

(l)(1) A revision may assign legal

authority to local agencies in

accordance with § 51.232 of this part.

(2) Each revision must comply with

§ 51.240 of this part (regarding general

plan requirements).

(m) Each revision must comply with

§ 51.280 of this part (regarding

resources).

(n) For purposes of the SIP revisions

required by this section, EPA may make

a finding as applicable under section

179(a)(1)–(4) of the CAA, 42 U.S.C.

7509(a)(1)–(4), starting the sanctions

process set forth in section 179(a) of the

CAA. Any such finding will be deemed

a finding under § 52.31(c) of this part

and sanctions will be imposed in

accordance with the order of sanctions

and the terms for such sanctions

established in § 52.31 of this part.

(o) Each revision must provide for

State compliance with the reporting

requirements set forth in § 51.122 of this

part.

(p)(1) Notwithstanding any other

provision of this section, if a State

adopts regulations substantively

identical to 40 CFR part 96 (the model

NOX budget trading program for SIPs),

incorporates such part by reference into

its regulations, or adopts regulations

that differ substantively from such part

only as set forth in paragraph (p)(2) of

this section, then that portion of the

State’s SIP revision is automatically

approved as satisfying the same portion

of the State’s NOX emission reduction

obligations as the State projects such

regulations will satisfy, provided that:
57496 Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations

(i) The State has the legal authority to

take such action and to implement its

responsibilities under such regulations,

and

(ii) The SIP revision accurately

reflects the NOX emissions reductions to

be expected from the State’s

implementation of such regulations.

(2) If a State adopts an emissions

trading program that differs

substantively from 40 CFR part 96 in

only the following respects, then such

portion of the State’s SIP revision is

approved as set forth in paragraph (p)(1)

of this section:

(i) The State may expand the

applicability provisions of the trading

program to include units (as defined in

40 CFR 96.2) that are smaller than the

size criteria thresholds set forth in 40

CFR 96.4(a);

(ii) The State may decline to adopt the

exemption provisions set forth in 40

CFR 96.4(b);

(iii) The State may decline to adopt

the opt-in provisions set forth in subpart

I of 40 CFR part 96;

(iv) The State may decline to adopt

the allocation provisions set forth in

subpart E of 40 CFR part 96 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 40 CFR 96.41;

and

(v) The State may decline to adopt the

early reduction credit provisions set

forth in 40 CFR 96.55(c) and may

instead adopt any methodology for

issuing credit from the State’s

compliance supplement pool that

complies with paragraph (e)(3) of this

section.

(3) If a State adopts an emissions

trading program that differs

substantively from 40 CFR part 96 other

than as set forth in paragraph (p)(2) of

this section, then such portion of the

State’s SIP revision is not automatically

approved as set forth in paragraph (p)(1)

of this section but will be reviewed by

the Administrator for approvability in

accordance with the other provisions of

this section.

§ 51.122 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) Annual reporting. Each revision

must provide for annual reporting of

NOX emissions data 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 annually 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

annual reporting to EPA for such

sources.

(2) Triennial reporting. Each plan

must provide for triennial (i.e., every

third year) reporting of NOX emissions

data from all sources within the State.

(3) Year 2007 reporting. Each plan

must provide for reporting of year 2007

NOX emissions data from all sources

within the State.

(4) 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),(2)

and (3) of this section.

(c) The data reported in paragraph (b)

of this section for stationary point

sources must meet the following

minimum criteria:

(1) For annual data reporting purposes

the data must include the following

minimum elements:

(i) Inventory year.

(ii) State Federal Information

Placement System code.

(iii) County Federal Information

Placement System code.

(iv) Federal ID code (plant).

(v) Federal ID code (point).

(vi) Federal ID code (process).

(vii) Federal ID code (stack).

(vii) Site name.

(viii) Physical address.

(ix) SCC.

(x) Pollutant code.

(xi) Ozone season emissions.

(xii) Area designation.

(2) In addition, the annual data must

include the following minimum

elements as applicable to the emissions

estimation methodology.

(i) Fuel heat content (annual).

(ii) Fuel heat content (seasonal).

(iii) Source of fuel heat content data.

(iv) Activity throughput (annual).

(v) Activity throughput (seasonal).

(vi) Source of activity/throughput

data.

(vii) Spring throughput (%).

(viii) Summer throughput (%).

(ix) Fall throughput (%).

(x) Work weekday emissions.

(xi) Emission factor.

(xii) Source of emission factor.

(xiii) Hour/day in operation.

(xiv) Operations Start time (hour).

(xv) Day/week in operation.

(xvi) Week/year in operation.

(3) The triennial and 2007 inventories

must include the following data

elements:

(i) The data required in paragraphs

(c)(1) and (c)(2) of this section.

(ii) X coordinate (latitude).

(iii) Y coordinate (longitude).

(iv) Stack height.

(v) Stack diameter.

(vi) Exit gas temperature.

(vii) Exit gas velocity.

(viii) Exit gas flow rate.

(ix) SIC.

(x) Boiler/process throughput design

capacity.

(xi) Maximum design rate.

(xii) Maximum capacity.

(xiii) Primary control efficiency.

(xiv) Secondary control efficiency.

(xv) Control device type.

(d) The data reported in paragraph (b)

of this section for area sources must

include the following minimum

elements:

(1) For annual inventories it must

include:

(i) Inventory year.

(ii) State FIPS code.

(iii) County FIPS code.

(iv) SCC.

(v) Emission factor.

(vi) Source of emission factor.

(vii) Activity/throughput level

(annual).

(viii) Activity throughput level

(seasonal).

(ix) Source of activity/throughput

data.

(x) Spring throughput (%).

(xi) Summer throughput (%).

(xii) Fall throughput (%).

(xiii) Control efficiency (%).

(xiv) Pollutant code.

(xv) Ozone season emissions.

(xvi) Source of emissions data.

(xvii) Hour/day in operation.

(xviii) Day/week in operation.

(xix) Week/year in operations.

(2) The triennial and 2007 inventories

must contain, at a minimum, all the data

required in paragraph (d)(1) of this

section.
Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations 57497

(e) The data reported in paragraph (b)

of this section for mobile sources must

meet the following minimum criteria:

(1) For the annual, triennial, and 2007

inventory purposes, the following data

must be reported:

(i) Inventory year.

(ii) State FIPS code.

(iii) County FIPS code.

(iv) SCC.

(v) Emission factor.

(vi) Source of emission factor.

(vii) Activity (this must be reported

for both highway and nonroad activity.

Submit nonroad activity in the form of

hours of activity at standard load (either

full load or average load) for each

engine type, application, and

horsepower range. Submit highway

activity in the form of vehicle miles

traveled (VMT) by vehicle class on each

roadway type. Report both highway and

nonroad activity for a typical ozone

season weekday day, if the State uses

EPA’s default weekday/weekend

activity ratio. If the State uses a different

weekday/weekend activity ratio, submit

separate activity level information for

weekday days and weekend days).

(viii) Source of activity data.

(ix) Pollutant code.

(x) Summer work weekday emissions.

(xi) Ozone season emissions.

(xii) Source of emissions data.

(2) [Reserved]

(f) 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 for EPA to

verify the calculated value of ozone

season emissions.

(g) Reporting schedules. (1) Annual

reports are to begin with data for

emissions occurring in the year 2003.

(2) Triennial reports are to begin with

data for emissions occurring in the year

2002.

(3) Year 2007 data are to be submitted

for emissions occurring in the year

2007.

(4) States must submit data for a

required year no later than 12 months

after the end of the calendar year for

which the data are collected.

(h) Data reporting procedures. When

submitting a formal NOX budget

emissions report and associated data,

States shall notify the appropriate EPA

Regional Office.

(1) States are required to report

emissions data in an electronic format to

one of the locations listed in this

paragraph (h). Several options are

available for data reporting.

(2) An agency may choose to continue

reporting to the EPA Aerometric

Information Retrieval System (AIRS)

system using the AIRS facility

subsystem (AFS) format for point

sources. (This option will continue for

point sources for some period of time

after AIRS is reengineered (before 2002),

at which time this choice may be

discontinued or modified.)

(3) An agency may convert its

emissions data into the Emission

Inventory Improvement Program/

Electronic Data Interchange (EIIP/EDI)

format. This file can then be made

available to any requestor, either using

E-mail, floppy disk, or value added

network (VAN), or can be placed on a

file transfer protocol (FTP) site.

(4) An agency may submit its

emissions data in a proprietary format

based on the EIIP data model.

(5) For options in paragraphs (h)(3)

and (4) of this section, the terms

submitting and reporting data are

defined as either providing the data in

the EIIP/EDI format or the EIIP based

data model proprietary format to EPA,

Office of Air Quality Planning and

Standards, Emission Factors and

Inventory Group, directly or notifying

this group that the data are available in

the specified format and at a specific

electronic location (e.g., FTP site).

(6) For annual reporting (not for

triennial reports), a State may have

sources submit the data directly to EPA

to the extent the sources are subject to

a trading program that qualifies for

approval under § 51.121(q) of this part,

and the State has agreed to accept data

in this format. The EPA will make both

the raw data submitted in this format

and summary data available to any State

that chooses this option.

(i) Definitions. As used in this section,

the following words and terms shall

have the meanings set forth below:

(1) Annual emissions. Actual

emissions for a plant, point, or process,

either measured or calculated.

(2) Ash content. Inert residual portion

of a fuel.

(3) Area designation. The designation

of the area in which the reporting source

is located with regard to the ozone

NAAQS. This would include attainment

or nonattainment designations. For

nonattainment designations, the

classification of the nonattainment area

must be specified, i.e., transitional,

marginal, moderate, serious, severe, or

extreme.

(4) Boiler design capacity. A measure

of the size of a boiler, based on the

reported maximum continuous steam

flow. Capacity is calculated in units of

MMBtu/hr.

(5) Control device type. The name of

the type of control device (e.g., wet

scrubber, flaring, or process change).

(6) Control efficiency. The emissions

reduction efficiency of a primary control

device, which shows the amount of

reductions of a particular pollutant from

a process’ emissions due to controls or

material change. Control efficiency is

usually expressed as a percentage or in

tenths.

(7) Day/week in operations. Days per

week that the emitting process operates.

(8) Emission factor. Ratio relating

emissions of a specific pollutant to an

activity or material throughput level.

(9) Exit gas flow rate. Numeric value

of stack gas flow rate.

(10) Exit gas temperature. Numeric

value of an exit gas stream temperature.

(11) Exit gas velocity. Numeric value

of an exit gas stream velocity.

(12) Fall throughput (%). Portion of

throughput for the 3 fall months

(September, October, November). This

represents the expression of annual

activity information on the basis of four

seasons, typically spring, summer, fall,

and winter. It can be represented either

as a percentage of the annual activity

(e.g., production in summer is 40

percent of the year’s production), or in

terms of the units of the activity (e.g.,

out of 600 units produced, spring = 150

units, summer = 250 units, fall = 150

units, and winter = 50 units).

(13) Federal ID code (plant). Unique

codes for a plant or facility, containing

one or more pollutant-emitting sources.

(14) Federal ID code (point). Unique

codes for the point of generation of

emissions, typically a physical piece of

equipment.

(15) Federal ID code (stack number).

Unique codes for the point where

emissions from one or more processes

are released into the atmosphere.

(16) Federal Information Placement

System (FIPS). The system of unique

numeric codes developed by the

government to identify States, counties,

towns, and townships for the entire

United States, Puerto Rico, and Guam.

(17) Heat content. The thermal heat

energy content of a solid, liquid, or

gaseous fuel. Fuel heat content is

typically expressed in units of Btu/lb of

fuel, Btu/gal of fuel, joules/kg of fuel,

etc.

(18) Hr/day in operations. Hours per

day that the emitting process operates.

(19) Maximum design rate. Maximum

fuel use rate based on the equipment’s

or process’ physical size or operational

capabilities.

(20) 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 (MW) or

kilowatts (KW).
57498 Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations

(21) Mobile source. A motor vehicle,

nonroad engine or nonroad vehicle,

where:

(i) Motor vehicle means any selfpropelled vehicle designed for

transporting persons or property on a

street or highway;

(ii) Nonroad engine means an internal

combustion engine (including the fuel

system) that is not used in a motor

vehicle or a vehicle used solely for

competition, or that is not subject to

standards promulgated under section

111 or section 202 of the CAA;

(iii) Nonroad vehicle means a vehicle

that is powered by a nonroad engine

and that is not a motor vehicle or a

vehicle used solely for competition.

(22) Ozone season. The period May 1

through September 30 of a year.

(23) Physical address. Street address

of facility.

(24) Point source. A non-mobile

source which emits 100 tons of NOX or

more per year unless the State

designates as a point source a nonmobile source emitting at a specified

level lower than 100 tons of NOX per

year. A non-mobile source which emits

less NOX per year than the point source

threshold is an area source.

(25) Pollutant code. A unique code for

each reported pollutant that has been

assigned in the EIIP Data Model.

Character names are used for criteria

pollutants, while Chemical Abstracts

Service (CAS) numbers are used for all

other pollutants. Some States may be

using storage and retrieval of aerometric

data (SAROAD) codes for pollutants, but

these should be able to be mapped to

the EIIP Data Model pollutant codes.

(26) Process rate/throughput. A

measurable factor or parameter that is

directly or indirectly related to the

emissions of an air pollution source.

Depending on the type of source

category, activity information may refer

to the amount of fuel combusted, the

amount of a raw material processed, the

amount of a product that is

manufactured, the amount of a material

that is handled or processed,

population, employment, number of

units, or miles traveled. Activity

information is typically the value that is

multiplied against an emission factor to

generate an emissions estimate.

(27) SCC. Source category code. A

process-level code that describes the

equipment or operation emitting

pollutants.

(28) Secondary control efficiency (%).

The emissions reductions efficiency of a

secondary control device, which shows

the amount of reductions of a particular

pollutant from a process’ emissions due

to controls or material change. Control

efficiency is usually expressed as a

percentage or in tenths.

(29) SIC. Standard Industrial

Classification code. U.S. Department of

Commerce’s categorization of businesses

by their products or services.

(30) Site name. The name of the

facility.

(31) Spring throughput (%). Portion of

throughput or activity for the 3 spring

months (March, April, May). See the

definition of Fall Throughput.

(32) Stack diameter. Stack physical

diameter.

(33) Stack height. Stack physical

height above the surrounding terrain.

(34) Start date (inventory year). The

calendar year that the emissions

estimates were calculated for and are

applicable to.

(35) Start time (hour). Start time (if

available) that was applicable and used

for calculations of emissions estimates.

(36) Summer throughput (%). Portion

of throughput or activity for the 3

summer months (June, July, August).

See the definition of Fall Throughput.

(37) Summer work weekday

emissions. Average day’s emissions for

a typical day.

(38) VMT by Roadway Class. This is

an expression of vehicle activity that is

used with emission factors. The

emission factors are usually expressed

in terms of grams per mile of travel.

Since VMT does not directly correlate to

emissions that occur while the vehicle

is not moving, these non-moving

emissions are incorporated into EPA’s

MOBILE model emission factors.

(39) Week/year in operation. Weeks

per year that the emitting process

operates.

(40) Work Weekday. Any day of the

week except Saturday or Sunday.

(41) X coordinate (latitude). East-west

geographic coordinate of an object.

(42) Y coordinate (longitude). Northsouth geographic coordinate of an

object.

PART 72—PERMITS REGULATION

1. The authority for part 72 continues

to read as follows:

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

2. Section 72.2 is amended by revising

the definition for ‘‘excepted monitoring

system,’’ and adding new definitions in

alphabetical order for ‘‘low mass

emissions unit’’, ‘‘maximum potential

hourly heat input’’, ‘‘maximum rated

hourly heat input,’’ and ‘‘ozone season’’

to read as follows:

§ 72.2 Definitions.

* * * * *

Excepted monitoring system means a

monitoring system that follows the

procedures and requirements of § 75.19

of this chapter or of appendix D or E to

part 75 for approved exceptions to the

use of continuous emission monitoring

systems.

* * * * *

Low mass emissions unit means an

affected unit that is a gas-fired or oilfired unit, burns only natural gas or fuel

oil and qualifies under § 75.19 of this

chapter.

* * * * *

Maximum potential hourly heat input

means an hourly heat input used for

reporting purposes when a unit lacks

certified monitors to report heat input.

If the unit intends to use appendix D of

part 75 of this chapter to report heat

input, this value should be calculated,

in accordance with part 75 of this

chapter, using the maximum fuel flow

rate and the maximum gross calorific

value. If the unit intends to use a flow

monitor and a diluent gas monitor, this

value should be reported, in accordance

with part 75 of this chapter, using the

maximum potential flow rate and either

the maximum carbon dioxide

concentration (in percent CO2) or the

minimum oxygen concentration (in

percent O2).

* * * * *

Maximum rated hourly heat input

means a unit-specific maximum hourly

heat input (mmBtu) which is the higher

of the manufacturer’s maximum rated

hourly heat input or the highest

observed hourly heat input.

* * * * *

Ozone season means the period of

time beginning May 1 of a year and

ending on September 30 of the same

year, inclusive.

* * * * *

PART 75—CONTINUOUS EMISSION

MONITORING

3. The authority citation for part 75

continues to read as follows:

Authority: 42 U.S.C. 7601 and 7651k, 7651

and note.

4. Section 75.1 is amended by revising

paragraph (a) to read as follows:

§ 75.1 Purpose and scope.

(a) Purpose. The purpose of this part

is to establish requirements for the

monitoring, recordkeeping, and

reporting of sulfur dioxide (SO2),

nitrogen oxides (NOX), and carbon

dioxide (CO2) emissions, volumetric

flow, and opacity data from affected

units under the Acid Rain Program

pursuant to sections 412 and 821 of the

CAA, 42 U.S.C. 7401–7671q as amended

by Public Law 101–549 (November 15,

1990). In addition, this part sets forth
Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations 57499

provisions for the monitoring,

recordkeeping, and reporting of NOX

mass emissions with which EPA,

individual States, or groups of States

may require sources to comply in order

to demonstrate compliance with a NOX

mass emission reduction program, to the

extent these provisions are adopted as

requirements under such a program.

* * * * *

5. Section 75.2 is amended by revising

paragraph (a) and adding a new

paragraph (c) to read as follows:

§ 75.2 Applicability.

(a) Except as provided in paragraphs

(b) and (c) of this section, the provisions

of this part apply to each affected unit

subject to Acid Rain emission

limitations or reduction requirements

for SO2 or NOX.

* * * * *

(c) The provisions of this part apply

to sources subject to a State or federal

NOX mass emission reduction program,

to the extent these provisions are

adopted as requirements under such a

program.

6. Section 75.4 is amended by revising

paragraph (a) introductory text to read

as follows:

§ 75.4 Compliance dates.

(a) The provisions of this part apply

to each existing Phase I and Phase II

unit on February 10, 1993. For

substitution or compensating units that

are so designated under the Acid Rain

permit which governs that unit and

contains the approved substitution or

reduced utilization plan, pursuant to

§ 72.41 or § 72.43 of this chapter, the

provisions of this part become

applicable upon the issuance date of the

Acid Rain permit. For combustion

sources seeking to enter the Opt-in

Program in accordance with part 74 of

this chapter, the provisions of this part

become applicable upon the submission

of an opt-in permit application in

accordance with § 74.14 of this chapter.

The provisions of this part for the

monitoring, recording, and reporting of

NOX mass emissions become applicable

on the deadlines specified in the

applicable State or federal NOX mass

emission reduction program, to the

extent these provisions are adopted as

requirements under such a program. In

accordance with § 75.20, the owner or

operator of each existing affected unit

shall ensure that all monitoring systems

required by this part for monitoring SO2,

NOX, CO2, opacity, and volumetric flow

are installed and that all certification

tests are completed no later than the

following dates (except as provided in

paragraphs (d) through (h) of this

section):

* * * * *

7. Section 75.6 is amended by adding

paragraph (f) to read as follows:

§ 75.6 Incorporation by reference.

* * * * *

(f) The following materials are

available for purchase from the

following address: American Petroleum

Institute, Publications Department, 1220

L Street NW, Washington, DC 20005–

4070.

(1) American Petroleum Institute

(API) Petroleum Measurement

Standards, Chapter 3, Tank Gauging:

Section 1A, Standard Practice for the

Manual Gauging of Petroleum and

Petroleum Products, December 1994;

Section 1B, Standard Practice for Level

Measurement of Liquid Hydrocarbons in

Stationary Tanks by Automatic Tank

Gauging, April 1992 (reaffirmed January

1997); Section 2, Standard Practice for

Gauging Petroleum and Petroleum

Products in Tank Cars, September 1995;

Section 3, Standard Practice for Level

Measurement of Liquid Hydrocarbons in

Stationary Pressurized Storage Tanks by

Automatic Tank Gauging, June 1996;

Section 4, Standard Practice for Level

Measurement of Liquid Hydrocarbons

on Marine Vessels by Automatic Tank

Gauging, April 1995; and Section 5,

Standard Practice for Level

Measurement of Light Hydrocarbon

Liquids Onboard Marine Vessels by

Automatic Tank Gauging, March 1997;

for § 75.19.

(2) Shop Testing of Automatic Liquid

Level Gages, Bulletin 2509 B, December

1961 (Reaffirmed August 1987, October

1992), for § 75.19.

8. Section 75.11 is amended by

removing the period at the end of

paragraph (d)(2) and replacing it with ‘‘;

or’’ and adding paragraph (d)(3), to read

as follows:

§ 75.11 Specific provisions for monitoring

SO2 emissions (SO2 and flow monitors).

* * * * *

(d)* * *

(3) By using the low mass emissions

excepted methodology in § 75.19(c) for

estimating hourly SO2 mass emissions if

the affected unit qualifies as a low mass

emissions unit under § 75.19(a) and (b).

* * * * *

9. Section 75.12 is amended by

revising the section heading, by

redesignating paragraph (d) as

paragraph (e), and by adding new

paragraph (d) to read as follows:

§ 75.12 Specific provisions for monitoring

NOX emission rate (NOX and diluent gas

monitors).

* * * * *

(d) Low mass emissions units.

Notwithstanding the requirements of

paragraphs (a) and (c) of this section, the

owner or operator of an affected unit

that qualifies as a low mass emissions

unit under § 75.19(a) and (b) shall

comply with one of the following:

(1) Meet the general operating

requirements in § 75.10 for a NOX

continuous emission monitoring system;

(2) Meet the requirements specified in

paragraph (d)(2) of this section for using

the excepted monitoring procedures in

appendix E to this part, if applicable; or

(3) Use the low mass emissions

excepted methodology in § 75.19(c) for

estimating hourly NOX emission rate

and hourly NOX mass emissions, if

applicable under § 75.19(a) and (b).

* * * * *

10. Section 75.13 is amended by

adding paragraph (d) to read as follows:

§ 75.13 Specific provisions for monitoring

CO2 emissions.

* * * * *

(d) Determination of CO2 mass

emissions from low mass emissions

units. The owner or operator of a unit

that qualifies as a low mass emissions

unit under § 75.19(a) and (b) shall

comply with one of the following:

(1) Meet the general operating

requirements in § 75.10 for a CO2

continuous emission monitoring system

and flow monitoring system;

(2) Meet the requirements specified in

paragraph (b) or (c) of this section for

use of the methods in appendix G or F

to this part, respectively; or

(3) Use the low mass emissions

excepted methodology in § 75.19(c) for

estimating hourly CO2 mass emissions,

if applicable under § 75.19(a) and (b).

* * * * *

11. Section 75.17 is amended by

adding introductory text before

paragraph (a) to read as follows:

§ 75.17 Specific provisions for monitoring

emissions from common, by-pass, and

multiple stacks for NOX emission rate.

Notwithstanding the provisions of

paragraphs (a), (b), and (c) of this

section, the owner or operator of an

affected unit that is using the

procedures in this part to meet the

monitoring and reporting requirements

of a State or federal NOX mass emission

reduction program must also meet the

provisions for monitoring NOX emission

rate in §§ 75.71 and 75.72.

* * * * *

12. Section 75.19 is added to subpart

B to read as follows:
57500 Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations

§ 75.19 Optional SO2, NOX, and CO2

emissions calculation for low mass

emissions units.

(a) Applicability. (1) Consistent with

the requirements of paragraphs (a)(2)

and (b) of this section, the low mass

emissions excepted methodology in

paragraph (c) of this section may be

used in lieu of continuous emission

monitoring systems or, if applicable, in

lieu of excepted methods under

appendix D or E to this part, for the

purpose of determining hourly heat

input and hourly NOX, SO2, and CO2

mass emissions from a low mass

emissions unit.

(i) A low mass emissions unit is an

affected unit that is gas-fired, or oil-fired

unit, that burns only natural gas or fuel

oil and for which:

(A) An initial demonstration is

provided, in accordance with paragraph

(a)(2) of this section, which shows that

the unit emits no more than 25 tons of

SO2 annually and no more than 50 tons

of NOX annually; and

(B) An annual demonstration is

provided thereafter, using one of the

allowable methodologies in paragraph

(c) of this section, showing that the low

mass emission unit continues to emit no

more than 25 tons of SO2 annually and

no more than 50 tons of NOX annually.

(ii) Any qualifying unit must start

using the low mass emissions excepted

methodology in the first hour in which

the unit operates in a calendar year.

Notwithstanding, the earliest date for

which a unit that meets the eligibility

requirements of this section may begin

to use this methodology is January 1,

2000.

(2) A unit may initially qualify as a

low mass emissions unit only under the

following circumstances:

(i) If the designated representative

submits a certification application to

use the low mass emissions excepted

methodology and the Administrator

certifies the use of such methodology.

The certification application must

contain:

(A) Actual SO2 and NOX mass

emissions data for each of the three

calendar years prior to the calendar year

in which the certification application is

submitted demonstrating to the

satisfaction of the Administrator that the

unit emits less than 25 tons of SO2 and

less than 50 tons of NOX annually; and

(B) Calculated SO2 and NOX mass

emissions, for each of the three calendar

years prior to the calendar year in which

the certification application is

submitted, demonstrating to the

satisfaction of the Administrator that the

unit emits less than 25 tons of SO2 and

less than 50 tons of NOX annually. The

calculated emissions for each year shall

be determined using either the

maximum rated heat input methodology

described in paragraph (c)(3)(i) of this

section or the long term fuel flow heat

input methodology described in

paragraph (c)(3)(ii) of this section, in

conjunction with the appropriate SO2,

NOX, and CO2 emission rate from

paragraph (c)(1)(i) of this section for

SO2, paragraph (c)(1)(ii) or (c)(1)(iv) of

this section for NOX and paragraph

(c)(1)(iii) of this section for CO2; or

(ii) When the three full years of

actual, historical SO2 and NOX mass

emissions data required under

paragraph (a)(2)(i) of this section are not

available, the designated representative

may submit an application to use the

low mass emissions excepted

methodology based upon a combination

of historical SO2 and NOX mass

emissions data and projected SO2 and

NOX mass emissions, totaling three

years. Historical data must be used for

any years in which historical data exists

and projected data should be used for

any remaining future years needed to

provide capacity factor data for three

consecutive calender years. For

example, if a unit commenced operation

two years ago, the designated

representative may submit actual,

historical data for the previous two

years and one year of projected

emissions for the current calendar year

or, for unit that commenced operation

after January 1, 1997, the designated

representative may submit three years of

projected emissions, beginning with the

current calendar year. Any actual or

projected annual emissions must

demonstrate to the satisfaction of the

Administrator that the unit will emit

less than 25 tons of SO2 and less than

50 tons of NOX annually. Projected

emissions shall be calculated using

either the default emission rates in

tables 1,2 and 3 of this section, or for

NOX emission rate a fuel-and-unitspecific NOX emission rate determined

in accordance with the testing

procedures in paragraph (c)(1)(iv) of this

section, in conjunction with projections

of unit operating hours or fuel type and

fuel usage, according to one of the

allowable calculation methodologies in

paragraph (c) of this section.

(b) On-going qualification and

disqualification. (1) Once a low mass

emission unit has qualified for and has

started using the low mass emissions

excepted methodology, an annual

demonstration is required, showing that

the unit continues to emit less than 25

tons of SO2 annually and less than 50

tons of NOX annually. The calculation

methodology used for the annual

demonstration shall be the same

methodology, from paragraph (c) of this

section, by which the unit initially

qualified to use the low mass emissions

excepted methodology.

(2) If any low mass emission unit fails

to provide the required annual

demonstration under paragraph (b)(1) of

this section, such that the calculated

cumulative year-to-date emissions for

the unit exceed 25 tons of SO2 or 50

tons of NOX in any calendar quarter of

any calendar year, then;

(i) The low mass emission unit shall

be disqualified from using the low mass

emissions excepted methodology as of

the end of the second calendar quarter

following such quarter in which either

the 25 ton limit for SO2 or the 50 ton

limit for NOX was exceeded; and

(ii) The owner or operator of the low

mass emission unit shall have two

calendar quarters from the end of the

quarter in which the unit exceeded the

25 ton limit for SO2 or the 50 ton limit

for NOX to install, certify, and report

SO2, NOX, and CO2 emissions from

monitoring systems that meet the

requirements of §§ 75.11, 75.12, and

75.13.

(3) If a low mass emission unit that

initially qualifies to use the low mass

emissions excepted methodology under

this section changes fuels, such that a

fuel other than those allowed for use in

the low mass emissions methodology

(e.g. natural gas or fuel oil) is combusted

in the unit, the unit shall be disqualified

from using the low mass emissions

excepted methodology as of the first

hour that the new fuel is combusted in

the unit. The owner or operator shall

install, certify, and report SO2, NOX,

and CO2 from monitoring systems that

meet the requirements of §§ 75.11,

75.12, and 75.13 prior to a change to

such fuel. The owner or operator must

notify the Administrator in the case

where a unit switches fuels without

previously having installed and certified

a SO2, NOX and CO2 monitoring system

meeting the requirements of §§ 75.11,

75.12, and 75.13.

(4) If a unit commencing operation

after January 1, 1997 initially qualifies

to use the low mass emissions excepted

methodology under this section and the

owner or operator wants to use a low

mass emissions methodology for the

unit, he or she must:

(i) Keep the records specified in

paragraph (c)(2) of this section,

beginning with the date and hour of

commencement of commercial

operation, for a unit subject to an Acid

Rain emission limitation, and beginning

with the date and hour of the

commencement of operation, for a unit

subject to a NOX mass reduction

program;
Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations 57501

(ii) Use these records to determine the

cumulative heat input and SO2, NOX,

and CO2 mass emissions in order to

continue to qualify as a low mass

emission unit; and

(iii) Determine the cumulative SO2

and NOX mass emissions according to

paragraph (c) of this section using the

same procedures used after the

certification deadline for the unit, for

purposes of demonstrating eligibility to

use the excepted methodology set forth

in this section. For example, use the

default emission rates in tables 1, 2 and

3 of this section or use the fuel-andunit-specific NOX emission rate

determined according to paragraph

(c)(1)(iv) of this section. The

Administrator will not count SO2 mass

emissions calculated for the period

between commencement of commercial

operation and the certification deadline

for the unit under § 75.4 against SO2

allowances to be held in the unit

account.

(5) A low mass emission unit that has

been disqualified from using the low

mass emissions excepted methodology

may subsequently qualify again to use

the low mass emissions methodology

under paragraph (a)(2) of this section,

provided that if such unit qualified

under paragraph (a)(2)(ii) of this section,

the unit may subsequently qualify again

only if the unit meets the requirements

of paragraph (a)(2)(i) of this section.

(c) Low mass emissions excepted

methodology, calculations, and values.

(1) Determination of SO2, NOX, and

CO2 emission rates.

(i) Use Table 1 of this section to

determine the appropriate SO2 emission

rate for use in calculating hourly SO2

mass emissions under this section.

(ii) Use either the appropriate NOX

emission factor from Table 2 of this

section, or a fuel-and-unit-specific NOX

emission rate determined according to

paragraph (c)(1)(iv) of this section, to

calculate hourly NOX mass emissions

under this section.

(iii) Use Table 3 of this section to

determine the appropriate CO2 emission

rate for use in calculating hourly CO2

mass emissions under this section.

(iv) In lieu of using the default NOX

emission rate from Table 2 of this

section, the owner or operator may, for

each fuel combusted by a low mass

emission unit, determine a fuel-andunit-specific NOX emission rate for the

purpose of calculating NOX mass

emissions under this section. This

option may be used by any unit which

qualifies to use the low mass emission

excepted methodology under paragraph

(a) of this section, and also by groups of

units which combust fuel from a

common source of supply and which

use the long term fuel flow methodology

under paragraph (c)(3)(ii) of this section

to determine heat input. If this option is

chosen, the following procedures shall

be used.

(A) Except as otherwise provided in

paragraphs (c)(1)(iv)(F) and (G) of this

paragraph, determine a fuel-and-unitspecific NOX emission rate by

conducting a four load NOX emission

rate test procedure as specified in

section 2.1 of appendix E to this part,

for each type of fuel combusted in the

unit. For a group of units sharing a

common fuel supply, the appendix E

testing must be performed on each

individual unit in the group, unless

some or all of the units in the group

belong to an identical group of units, as

defined in paragraph (c)(1)(iv)(B) of this

section, in which case, representative

testing may be conducted on units in

the identical group of units, as

described in paragraph (c)(1)(iv)(B) of

this section. For the purposes of this

section, make the following

modifications to the appendix E test

procedures:

(1) Do not measure the heat input as

required under 2.1.3 of appendix E to

this part.

(2) Do not plot the test results as

specified under 2.1.6 of appendix E to

this part.

(B) Representative appendix E testing

may be done on low mass emission

units in a group of identical units. All

of the units in a group of identical units

must combust the same fuel type but do

not have to share a common fuel supply.

(1) To be considered identical, all low

mass emission units must be of the same

size (based on maximum rated hourly

heat input), manufacturer and model,

and must have the same history of

modifications (e.g., have the same

controls installed, the same types of

burners and have undergone major

overhauls at the same frequency (based

on hours of operation)). Also, under

similar operating conditions, the stack

or turbine outlet temperature of each

unit must be within ±50 degrees

Fahrenheit of the average stack or

turbine outlet temperature for all of the

units.

(2) If all of the low mass emission

units in the group qualify as identical,

then representative testing of the units

in the group may be performed

according to Table 4 of this section.

(3) If there are only two low mass

emission units in the group of identical

units, the results of the representative

testing under paragraph (c)(1)(iv)(B)(1)

of this section may be used to establish

the fuel-and-unit-specific NOX emission

rate(s) for the units. However, if there

are more than two low mass emission

units in the group, the testing must

confirm that the units are identical by

meeting the following criteria. The

results of the representative testing may

only be used to establish the fuel-andunit-specific NOX emission rate(s) for

such units if the following criteria are

met:

(i) at each of the four load levels

tested, the NOX emission rate for each

tested low mass emission unit does not

differ by more than ±10% from the

average of the NOX emission rates for all

units tested, or;

(ii) if the average NOX emission rate

of all low mass emission units tested at

all four load levels is less than 0.20 lb/

mmBtu, an alternative criteria of ±0.020

lb/mmBtu may be use in lieu of the 10%

criteria. Units must all be within +0.020

lb/mmBtu of the average from the test to

be considered identical units under this

section.

(4) If the acceptance criteria in

paragaph (c)(1)(iv)(B)(3) of this section

are not met then the group of low mass

emission units is not considered an

identical group of units and individual

appendix E testing of each unit is

required.

(5) Fuel and unit specific NOX

emission rates determined according to

paragraphs (c)(1)(iv)(F) and (c)(1)(iv)(G)

of this section may be used in lieu of

appendix E testing for one or more low

mass emission units in a group of

identical units.

(C) Based on the results of the

appendix E testing, determine the fueland-unit-specific NOX emission rate as

follows:

(1) For an individual low mass

emission unit with no NOX emissions

controls of any kind, the highest NOX

emission rate obtained for a particular

type of fuel in the appendix E test

multiplied by 1.15 shall be the fuel-andunit-specific NOX emission rate, for that

type of fuel.

(2) For a group of low mass emission

units sharing a common fuel supply

with no NOX controls of any kind on

any of the units, the highest NOX

emission rate obtained for a particular

type of fuel in all of the appendix E tests

of all units in the group of units sharing

a common fuel supply multiplied by

1.15 shall be the fuel-and-unit-specific

NOX emission rate for each unit in the

group, for that type of fuel.

(3) For a group of identical low mass

emission units which perform

representative testing according to

paragraph (c)(1)(iv)(B) of this section

with no NOX controls of any kind on

any of the units, the fuel-and-unitspecific NOX emission rate for all units,

for a particular type of fuel, multiplied

by 1.15 shall be the highest NOX
57502 Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations

emission rate from any unit tested in the

group, for that type of fuel.

(4) For an individual low mass

emission unit which has NOX emission

controls of any kind, the fuel-and-unitspecific NOX emission rate for each type

of fuel combusted in the unit shall be

the higher of:

(i) The highest emission rate from the

appendix E test for that type of fuel

multiplied by 1.15; or

(ii) 0.15 lb/mmBtu.

(5) For a group of low mass emission

units sharing a common fuel supply,

one or more of which has NOX controls

of any kind, the fuel-and-unit-specific

NOX emission rate for each unit in the

group of units sharing a common fuel

supply shall, for a particular type of fuel

combusted by the group of units sharing

a common fuel supply, shall be the

higher of:

(i) The highest NOX emission rate

from all appendix E tests of all low mass

emission units in the group for that type

of fuel multiplied by 1.15; or

(ii) 0.15 lb/mmBtu.

(6) For a group of identical low mass

emission units, which perform

representative testing according to

paragraph (c)(1)(iv)(B) of this section

and have identical NOX controls, the

fuel-and-unit-specific NOX emission

rate for each unit in the group of units,

for a particular type of fuel, shall be the

higher of:

(i) The highest NOX emission rate

from all appendix E tests of all tested

low mass emission units in the group of

identical units for that type of fuel

multiplied by 1.15; or

(ii) 0.15 lb/mmBtu.

(D) For each low mass emission unit,

each unit in a group of units sharing a

common fuel supply, or identical units

for which the provisions of paragraph

(c)(1)(iv) of this section are used to

account for NOX emission rate, the

owner or operator shall determine a new

fuel-and-unit-specific NOX emission

rate every five years, unless changes in

the fuel supply, physical changes to the

unit, changes in the manner of unit

operation, or changes to the emission

controls occur which may cause a

significant increase in the unit’s actual

NOX emission rate. If such changes

occur, the fuel-and-unit-specific NOX

emission rate(s) shall be re-determined

according to paragraph (c)(1)(iv) of this

section. If a low mass emission unit

belongs to a group of identical units and

it is required to retest to determine a

new fuel-and-unit-specific NOX

emission rate because of changes in the

fuel supply, physical changes to the

unit, changes in the manner of unit

operation or changes to the emission

controls occur which may cause a

significant increase in the unit’s actual

NOX emission rate, any other unit in

that group of identical units is not

required to re-determine the fuel-andunit-specific NOX emission rate unless

such unit also undergoes changes in the

fuel supply, physical changes to the

unit, changes in the manner of unit

operation or changes to the emission

controls occur which may cause a

significant increase in the unit’s actual

NOX emission rates.

(E) Each low mass emission unit, each

low mass emission unit in a group of

units combusting a common fuel, or

each low mass emission unit in a group

of identical units for which a fuel-andunit-specific NOX emission rate(s) are

determined shall meet the quality

assurance and quality control provisions

of paragraph (e) of this section.

(F) Low mass emission units may use

the results of appendix E testing, if such

test results are available from a test

conducted no more than five years prior

to the time of initial certification, to

determine the appropriate fuel-and-unitspecific NOX emission rate(s). However,

fuel-and-unit-specific NOX emission

rates from historical testing may not be

used longer than five years after the

appendix E testing was conducted.

(G) Low mass emission units for

which at least 3 years of NOX emission

rate continuous emissions monitoring

system data and corresponding fuel

usage data are available may determine

fuel-and-unit-specific NOX emission

rates from the actual data using the

following procedure. Separate the actual

NOX emission rate data into groups,

according to the type of fuel combusted.

Discard data from periods when

multiple fuels were combusted. Each

fuel-specific data set must contain at

least 168 hours of data and must

represent all normal operating ranges of

the unit when combusting the fuel. Sort

the data in each fuel-specific data set in

ascending order according to NOX

emission rate. Determine the 95th

percentile NOX emission rate for each

data set as defined in § 72.2 of this

chapter. Use the 95th percentile value

for each data set as the fuel-and-unitspecific NOX emission rate, except that

for a unit with NOX emission controls

of any kind, if the 95th percentile value

is less than 0.15 lb/mmBtu, a value of

0.15 lb/mmBtu shall be used as the fueland-unit-specific NOX emission rate.

(H) For low mass emission units with

NOX emission controls, the owner or

operator shall, during every hour of unit

operation during the test period,

monitor and record parameters, as

required under paragraph (e)(5) of this

section, which indicate that the NOX

emission controls are operating

properly. After the test period, these

same parameters shall be monitored and

recorded and kept for all operating

hours in order to determine whether the

NOX controls are operating properly and

to allow the determination of the correct

NOX emission rate as required under

paragraph (c)(1)(iv) of this section.

(1) For low mass emission units with

steam or water injection, the steam-tofuel or water-to-fuel ratio used during

the testing must be documented. The

water-to-fuel or steam-to-fuel ratio must

be maintained during unit operations

for a unit to use the fuel and unit

specific NOX emission rate determined

during the test. Owners or operators

must include in the monitoring plan the

acceptable range of the water-to-fuel or

steam-to-fuel ratio, which will be used

to indicate hourly, proper operation of

the NOX controls for each unit. The

water-to-fuel or steam-to-fuel ratio shall

be monitored and recorded during each

hour of unit operation. If the water-tofuel or steam-to-fuel ratio is not within

the acceptable range in a given hour the

fuel and unit specific NOX emission rate

may not be used for that hour.

(2) For low mass emission units with

other types of NOX controls, appropriate

parameters and the acceptable range of

the parameters which indicate hourly

proper operation of the NOX controls

must be specified in the monitoring

plan. These parameters shall be

monitored during each subsequent

operating hour. If any of these

parameters are not within the acceptable

range in a given operating hour, the fuel

and unit specific NOX emission rates

may not be used in that hour.

(2) Records of operating time, fuel

usage, unit output and NOX emission

control operating status. The owner or

operator shall keep the following

records on-site, for three years, in a form

suitable for inspection:

(i) For each low mass emission unit,

the owner or operator shall keep hourly

records which indicate whether or not

the unit operated during each clock

hour of each calendar year. The owner

or operator may report partial operating

hours or may assume that for each hour

the unit operated the operating time is

a whole hour. Units using partial

operating hours and the maximum rated

hourly heat input to calculate heat input

for each hour must report partial

operating hours.

(ii) For each low mass emissions unit,

the owner or operator shall keep hourly

records indicating the type(s) of fuel(s)

combusted in the unit during each hour

of unit operation.

(iii) For each low mass emission unit

using the long term fuel flow

methodology under paragraph (c)(3)(ii)
Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations 57503

of this section to determine hourly heat

input, the owner or operator shall keep

hourly records of unit output (in

megawatts or thousands of pounds of

steam), for the purpose of apportioning

heat input to the individual unit

operating hours.

(iv) For each low mass emission unit

with NOX emission controls of any kind,

the owner or operator shall keep hourly

records of the hourly value of the

parameter(s) specified in (c)(1)(iv)(H) of

this section used to indicate proper

operation of the unit’s NOX controls.

(3) Heat input. Hourly, quarterly and

annual heat input for a low mass

emission unit shall be determined using

either the maximum rated hourly heat

input method under paragraph (c)(3)(i)

of this section or the long term fuel flow

method under paragraph (c)(3)(ii) of this

section.

(i) Maximum rated hourly heat input

method. (A) For the purposes of the

mass emission calculation methodology

of paragraph (c)(3) of this section, the

hourly heat input (mmBtu) to a low

mass emission unit shall be deemed to

equal the maximum rated hourly heat

input, as defined in § 72.2 of this

chapter, multiplied by the operating

time of the unit for each hour. The

owner or operator may choose to record

and report partial operating hours or

may assume that a unit operated for a

whole hour for each hour the unit

operated. However, the owner or

operator of a unit may petition the

Administrator under § 75.66 for a lower

value for maximum rated hourly heat

input than that defined in § 72.2 of this

chapter. The Administrator may

approve such lower value if the owner

or operator demonstrates that either the

maximum hourly heat input specified

by the manufacturer or the highest

observed hourly heat input, or both, are

not representative, and such a lower

value is representative, of the unit’s

current capabilities because

modifications have been made to the

unit, limiting its capacity permanently.

(B) The quarterly heat input, HIqtr, in

mmBtu, shall be determined using

Equation LM–1:

HIqtr = Tqtr × HIhr (Eq. LM–1)

Where:

Tqtr = Actual number of operating hours

in the quarter (hr).

HIhr = Hourly heat input under

paragraph (c)(3)(i)(A) of this section

(mmBtu).

(C) The year-to-date cumulative heat

input (mmBtu) shall be the sum of the

quarterly heat input values for all of the

calendar quarters in the year to date.

(ii) Long term fuel flow heat input

method. The owner or operator may, for

the purpose of demonstrating that a low

mass emission unit or group of low

mass emission units sharing a common

fuel supply meets the requirements of

this section, use records of long-term

fuel flow, to calculate hourly heat input

to a low mass emission unit.

(A) This option may be used for a

group of low mass emission units only

if:

(1) The low mass emission units

combust fuel from a common source of

supply; and

(2) Records are kept of the total

amount of fuel combusted by the group

of low mass emission units and the

hourly output (in megawatts or pounds

of steam) from each unit in the group;

and

(3) All of the units in the group are

low mass emission units.

(B) For each fuel used during the

quarter, the volume in standard cubic

feet (for gas) or gallons (for oil) may be

determined using any of the following

methods;

(1) Fuel billing records (for low mass

emission units, or groups of low mass

emission units, which purchase fuel

from non-affiliated sources);

(2) American Petroleum Institute

(API) standard, American Petroleum

Institute (API) Petroleum Measurement

Standards, Chapter 3, Tank Gauging:

Section 1A, Standard Practice for the

Manual Gauging of Petroleum and

Petroleum Products, December 1994;

Section 1B, Standard Practice for Level

Measurement of Liquid Hydrocarbons in

Stationary Tanks by Automatic Tank

Gauging, April 1992 (reaffirmed January

1997); Section 2, Standard Practice for

Gauging Petroleum and Petroleum

Products in Tank Cars, September 1995;

Section 3, Standard Practice for Level

Measurement of Liquid Hydrocarbons in

Stationary Pressurized Storage Tanks by

Automatic Tank Gauging, June 1996;

Section 4, Standard Practice for Level

Measurement of Liquid Hydrocarbons

on Marine Vessels by Automatic Tank

Gauging, April 1995; and Section 5,

Standard Practice for Level

Measurement of Light Hydrocarbon

Liquids Onboard Marine Vessels by

Automatic Tank Gauging, March 1997;

Shop Testing of Automatic Liquid Level

Gages, Bulletin 2509 B, December 1961

(Reaffirmed August 1987, October 1992)

(incorporated by reference under § 75.6);

or;

(3) A fuel flow meter certified and

maintained according to appendix D to

this part.

(C) For each fuel combusted during a

quarter, the gross calorific value of the

fuel shall be determined by either:

(1) Using the applicable procedures

for gas and oil analysis in sections 2.2

and 2.3 of appendix D to this part. If this

option is chosen the highest gross

calorific value recorded during the

previous calendar year shall be used; or

(2) Using the appropriate default gross

calorific value listed in Table 5 of this

section.

(D) For each type of fuel oil

combusted during the quarter, the

specific gravity of the oil shall be

determined either by:

(1) Using the procedures in section

2.2.6 of appendix D to this part. If this

option is chosen, use the highest

specific gravity value recorded during

the previous calendar year shall be

used; or

(2) Using the appropriate default

specific gravity value in Table 5 of this

section.

(E) The quarterly heat input from each

type of fuel combusted during the

quarter by a low mass emission unit or

group of low mass emission units

sharing a common fuel supply shall be

determined using Equation LM–2 for oil

and LM–3 for natural gas.

HI M GCV

fuel qtr --qtr = max

106

Eq LM–2 (for fuel oil or diesel fuel)

Where:

HIfuel-qtr = Quarterly total heat input from

oil (mmBtu).

Mqtr = Mass of oil consumed during the

entire quarter, determined as the

product of the volume of oil under

paragraph (c)(3)(ii)(B) of this section

and the specific gravity under

paragraph (c)(3)(ii)(D) of this

section (lb)

GCVmax = Gross calorific value of oil, as

determined under paragraph

(c)(3)(ii)(C) of this section (Btu/lb)

106 =Conversion of Btu to mmBtu.

HI Q GCV

fuel g --qtr = max

106

Eq LM–3 (for natural gas)

Where:

HIfuel-qtr = Quarterly heat input from

natural gas (mmBtu).

Qg = Value of natural gas combusted

during the quarter, as determined

under paragraph (c)(3)(ii)(B) of this

section standard cubic feet (scf).

GCVg = Gross calorific value of the

natural gas combusted during the

quarter, as determined under

paragraph (c)(3)(ii)(C) of this section

(Btu/scf)

106 =Conversion of Btu to mmBtu.

(F) The quarterly heat input (mmBtu)

for all fuels for the quarter, HIqtr-total,

shall be the sum of the HIfuel-qtr values

determined using Equations LM–2 and

LM–3.
57504 Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations

HI HI qtr total

all

fuel qtr --

--fuels -- = ∑

(Eq. LM–4)

(G) The year-to-date cumulative heat

input (mmBtu) for all fuels shall be the

sum of all quarterly total heat input

(HIqtr-total) values for all calendar

quarters in the year to date.

(H) For each low mass emission unit,

each low mass emission unit of an

identical group of units, or each low

mass emission unit in a group of units

sharing a common fuel supply, the

owner or operator shall determine the

quarterly unit output in megawatts or

pounds of steam. The quarterly unit

output shall be the sum of the hourly

unit output values recorded under

paragraph (c)(2) of this section and shall

be determined using Equations LM–5 or

LM–6.

MW MW qtr

all

= ∑

--hours

Eq LM–5 (for MW output)

ST ST qtr

all

= ∑

--hours

Eq LM–6 (for steam output)

Where:

MWqtr = the power produced during all

hours of operation during the

quarter by the unit (MW)

STfuel-qtr = the total quarterly steam

output produced during all hours of

operation during the quarter by the

unit (klb)

MW = the power produced during each

hour in which the unit operated

during the quarter (MW).

ST = the steam output produced during

each hour in which the unit

operated during the quarter (klb)

(I) For a low mass emission unit that

is not included in a group of low mass

emission units sharing a common fuel

supply, apportion the total heat input

for the quarter, HIqtr-total to each hour of

unit operation using either Equation

LM–7 or LM–8:

HI HI hr qtr = --total

hr

qtr

MW

MW

(Eq LM–7 for MW output)

HI HI hr qtr = --total

hr

qtr

ST

ST

(Eq LM–8 for steam output)

Where:

HIhr = hourly heat input to the unit

(mmBtu)

MWhr = hourly output from the unit

(MW)

SThr = hourly steam output from the unit

(klb)

(J) For each low mass emission unit

that is included in a group of units

sharing a common fuel supply,

apportion the total heat input for the

quarter, HIqtr-total to each hour of

operation using either Equation LM–7a

or LM–8a:

HI HI MW

hr qtr

hr

all

=

∑ --total

qtr

--units

MW

(Eq LM–7a for MW output)

HI HI ST

hr qtr

hr

all

=

∑ --total

qtr

--units

ST

(Eq LM–8a for steam output)

Where:

HIhr = hourly heat input to the

individual unit (mmBtu)

MWhr = hourly output from the

individual unit (MW)

SThr = hourly steam output from the

individual unit (klb)

MW Sum of the quarterly outputs (from Eq. LM-5) for all units

in the group (MW)

ST Sum of the quarterly steam

outputs (from Eq. LM-6) for all

units in the group (klb)

qtr

--units

qtr

--units

=

=

∑

∑

all

all

(4) Calculation of SO2, NOX and CO2

mass emissions. The owner or operator

shall, for the purpose of demonstrating

that a low mass emission unit meets the

requirements of this section, calculate

SO2, NOX and CO2 mass emissions in

accordance with the following.

(i) SO2 mass emissions. (A) The

hourly SO2 mass emissions (lbs) for a

low mass emission unit shall be

determined using Equation LM–9 and

the appropriate fuel-based SO2 emission

factor from Table 1 of this section for

the fuels combusted in that hour. If

more than one fuel is combusted in the

hour, use the highest emission factor for

all of the fuels combusted in the hour.

If records are missing as to which fuel

was combusted in the hour, use the

highest emission factor for all of the

fuels capable of being combusted in the

unit.

WSO2=EFSO2×HIhr (Eq. LM–9)

where:

WSO2=Hourly SO2 mass emissions (lbs).

EFSO2=SO2 emission factor from Table 1

of this section (lb/mmBtu).

HIhr=Either the maximum rated hourly

heat input under paragraph

(c)(3)(i)(A) of this section or the

hourly heat input under paragraph

(c)(3)(ii) of this section (mmBtu).

(B) The quarterly SO2 mass emissions

(tons) for the low mass emission unit

shall be the sum of all the hourly SO2

mass emissions in the quarter, as

determined under paragraph (c)(4)(i)(A)

of this section, divided by 2000 lb/ton.

(C) The year-to-date cumulative SO2

mass emissions (tons) for the low mass

emission unit shall be the sum of the

quarterly SO2 mass emissions, as

determined under paragraph (c)(4)(i)(B)

of this section, for all of the calendar

quarters in the year to date.

(ii) NOX mass emissions. (A) The

hourly NOX mass emissions for the low

mass emission unit (lbs) shall be

determined using Equation LM–10. If

more than one fuel is combusted in the

hour, use the highest emission rate for

all of the fuels combusted in the hour.

If records are missing as to which fuel

was combusted in the hour, use the

highest emission factor for all of the

fuels capable of being combusted in the

unit. For low mass emission units with

NOX emission controls of any kind and

for which a fuel-and-unit-specific NOX

emission rate is determined under

paragraph (c)(1)(iv) of this section, for

any hour in which the parameters under

paragraph (c)(1)(iv)(A) of this section do

not show that the NOX emission

controls are operating properly, use the

NOX emission rate from Table 2 of this

section for the fuel combusted during

the hour with the highest NOX emission

rate.

WNOx=EFNOx×HIhr (Eq. LM–10)

Where:

WNOX=Hourly NOX mass emissions

(lbs).

EFNOX=Either the NOX emission factor

from Table 1b of paragraph (c)(1)(ii)

of this section of this section or the

fuel-and-unit-specific NOX

emission rate determined under

paragraph (c)(1)(iv) of this section

(lb/mmBtu).

HIhr=Either the maximum rated hourly

heat input from paragraph

(c)(3)(i)(A) of this section or the

hourly heat input as determined

under paragraph(c)(3)(ii) of this

section (mmBtu).

(B) The quarterly NOX mass emissions

(tons) for the low mass emission unit

shall be the sum of all of the hourly

NOX mass emissions in the quarter, as

determined under paragraph (c)(4)(ii)(A)

of this section, divided by 2000 lb/ton.

(C) The year-to-date cumulative NOX

mass emissions (tons) for the low mass

emission unit shall be the sum of the
Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations 57505

quarterly NOX mass emissions, as

determined under paragraph (c)(4)(ii)(B)

of this section, for all of the calendar

quarters in the year to date.

(iii) CO2 Mass Emissions. (A) The

hourly CO2 mass emissions (tons) for

the affected low mass emission unit

shall be determined using Equation LM–

11 and the appropriate fuel-based CO2

emission factor from Table 3 of this

section for the fuel being combusted in

that hour. If more than one fuel is

combusted in the hour, use the highest

emission factor for all of the fuels

combusted in the hour. If records are

missing as to which fuel was combusted

in the hour, use the highest emission

factor for all of the fuels capable of

being combusted in the unit.

WCO2 = EFCO2 × HIhr (Eq. LM–11)

Where:

WCO2 = Hourly CO mass emissions

(tons).

EFCO2 = Fuel-based CO2 emission factor

from Table 3 of this section (ton/

mmBtu).

HIhr = Either the maximum rated hourly

heat input from paragraph

(c)(3)(i)(A) of this section or the

hourly heat input as determined

under paragraph (c)(3)(ii) of this

section (mmBtu).

(B) The quarterly CO2 mass emissions

(tons) for the low mass emission unit

shall be the sum of all of the hourly CO2

mass emissions in the quarter, as

determined under paragraph

(c)(4)(iii)(A)of this section.

(C) The year-to-date cumulative CO2

mass emissions (tons) for the low mass

emission unit shall be the sum of all of

the quarterly CO2 mass emissions, as

determined under paragraph

(c)(4)(iii)(B) of this section, for all of the

calendar quarters in the year to date.

(d) Each unit that qualifies under this

section to use the low mass emissions

methodology must follow the

recordkeeping and reporting

requirements pertaining to low mass

emissions units in subparts F and G of

this part.

(e) The quality control and quality

assurance requirements in § 75.21 are

not applicable to a low mass emissions

unit for which the low mass emissions

excepted methodology under paragraph

(c) of this section is being used in lieu

of a continuous emission monitoring

system or an excepted monitoring

system under appendix D or E to this

part, except for fuel flowmeters used to

meet the provisions in paragraph

(c)(3)(ii) of this section. However, the

owner or operator of a low mass

emissions unit shall implement the

following quality assurance and quality

control provisions:

(1) For low mass emission units or

groups of units which use the long term

fuel flow methodology under paragraph

(c)(3)(ii) of this section and which use

fuel billing records to determine fuel

usage, the owner or operator shall keep,

at the facility, for three years, the

records of the fuel billing statements

used for long term fuel flow

determinations.

(2) For low mass emission units or

groups of units which use the long term

fuel flow methodology under paragraph

(c)(3)(ii) of this section and which use

American Petroleum Institute (API)

standard, American Petroleum Institute

(API) Petroleum Measurement

Standards, Chapter 3, Tank Gauging:

Section 1A, Standard Practice for the

Manual Gauging of Petroleum and

Petroleum Products, December 1994;

Section 1B, Standard Practice for Level

Measurement of Liquid Hydrocarbons in

Stationary Tanks by Automatic Tank

Gauging, April 1992 (reaffirmed January

1997); Section 2, Standard Practice for

Gauging Petroleum and Petroleum

Products in Tank Cars, September 1995;

Section 3, Standard Practice for Level

Measurement of Liquid Hydrocarbons in

Stationary Pressurized Storage Tanks by

Automatic Tank Gauging, June 1996;

Section 4, Standard Practice for Level

Measurement of Liquid Hydrocarbons

on Marine Vessels by Automatic Tank

Gauging, April 1995; and Section 5,

Standard Practice for Level

Measurement of Light Hydrocarbon

Liquids Onboard Marine Vessels by

Automatic Tank Gauging, March 1997,

Shop Testing of Automatic Liquid Level

Gages, Bulletin 2509 B, December 1961

(Reaffirmed August 1987, October 1992)

(incorporated by reference under § 75.6),

to determine fuel usage, the owner or

operator shall keep, at the facility, a

copy of the standard used and shall

keep records, for three years, of all

measurements obtained for each quarter

using the methodology.

(3) For low mass emission units or

groups of units which use the long term

fuel flow methodology under paragraph

(c)(3)(ii) of this section and which use

a certified fuel flow meter to determine

fuel usage, the owner or operator shall

comply with the quality control quality

assurance requirements for a fuel flow

meter under section 2.1.6 of appendix D

of this part.

(4) For each low mass emission unit

for which fuel-and-unit-specific NOX

emission rates are determined in

accordance with paragraph (c)(1)(iv) of

this section, the owner or operator shall

keep, at the facility, records which

document the results of all NOX

emission rate tests conducted according

to appendix E to this part. If CEMS data

are used to determine the fuel-and-unitspecific NOX emission rates under

paragraph (c)(1)(iv)(G) of this section,

the owner or operator shall keep, at the

facility, records of the CEMS data and

the data analysis performed to

determine a fuel-and-unit-specific NOX

emission rate. The appendix E test

records and historical CEMS data

records shall be kept until the fuel and

unit specific NOX emission rates are redetermined.

(5) For each low mass emission unit

for which fuel-and-unit-specific NOX

emission rates are determined in

accordance with paragraph (c)(1)(iv) of

this section and which have NOX

emission controls of any kind, the

owner or operator shall develop and

keep on-site a quality assurance plan

which explains the procedures used to

document proper operation of the NOX

emission controls. The plan shall

include the parameters monitored (e.g.,

water-to-fuel ratio) and the acceptable

ranges for each parameter used to

determine proper operation of the unit’s

NOX controls.

TABLE 1 OF § 75.19: SO2 Emission

Factors (lb/mmBtu) for Various

Fuel Types

Fuel type SO2 emission factors

Pipeline Natural Gas 0.0006 lb/mmBtu.

Other Natural Gas ..... 0.06 lb/mmBtu.

Residual Oil ............... 2.1 lb/mmBtu.

Diesel Fuel ................ 0.5 lb/mmBtu.

TABLE 2 OF § 75.19: NOX Emission

Rates (lb/mmBtu) for Various Boiler/Fuel Types

Boiler type Fuel

type

NOX

emission

rate

Turbine ......................... Gas .... 0.7

Turbine ......................... Oil ....... 1.2

Boiler ............................ Gas .... 1.5

Boiler ............................ Oil ....... 2

TABLE 3 OF § 75.19: CO2 Emission

Factors (ton/mmBtu) for Gas and Oil

Fuel type CO2 emission factors

Natural Gas ............... 0.059 ton/mmBtu.

Oil .............................. 0.081 ton/mmBtu.

TABLE 4 OF § 75.19: IDENTICAL UNIT

TESTING REQUIREMENTS

Number of identical

units in the group

Number of appendix

E tests required

2 ................................ 1

3 to 6 ......................... 2
57506 Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations

TABLE 4 OF § 75.19: IDENTICAL UNIT

TESTING REQUIREMENTS—Continued

Number of identical

units in the group

Number of appendix

E tests required

7 ................................ 3

> 7 .............................. n tests; wheren n =

number of units divided by 3 and

rounded to nearest

integer.

TABLE 5 OF § 75.19: DEFAULT GROSS

CALORIFIC VALUES (GCVS) FOR

VARIOUS FUELS

Fuel GCV for use in equation LM–2 or LM–3

Pipeline Natural Gas 1051 Btu/scf.

Natural Gas ............... 1118 Btu/scf.

Residual Oil ............... 19,708 Btu/gallon.

Diesel Fuel ................ 20,500 Btu/gallon.

TABLE 6 OF § 75.19: DEFAULT SPECIFIC GRAVITY VALUES FOR FUEL

OIL

Fuel

Specific

gravity (lb/

gal)

Residual Oil ................................ 8.5

Diesel Fuel .................................. 7.4

13. Section 75.20 is amended by

adding new paragraph (h) to read as

follows:

§ 75.20 Certification and recertification

procedures.

* * * * *

(h) Initial certification and

recertification procedures for low mass

emission units using the excepted

methodologies under § 75.19. The owner

or operator of a gas-fired or oil-fired unit

using the low mass emissions excepted

methodology under § 75.19 shall meet

the applicable general operating

requirements of § 75.10, the applicable

requirements of § 75.19, and the

applicable certification requirements of

this paragraph.

(1) Monitoring plan. The designated

representative shall submit a monitoring

plan in accordance with §§ 75.53 and

75.62. The designated representative for

an owner or operator who wishes to use

fuel-and unit-specific NOX emission rate

testing for units with NOX controls

under § 75.19(c)(1)(iv) must submit in

the monitoring plan the parameters

monitored which will be used to

determine operation of the NOX

emission controls. For units using water

or steam injection to control NOX, the

water-to-fuel or steam-to-fuel range of

values must be documented.

(2) Certification application.

[reserved]

(3) Approval of certification

applications. The provisions for the

certification application formal approval

process in the introductory text of

paragraph (a)(4) and in paragraphs

(a)(4)(i), (ii), and (iv) of this section shall

apply, except that ‘‘continuous emission

or opacity monitoring system’’ shall be

replaced with ‘‘excepted methodology.’’

The excepted methodology shall be

deemed provisionally certified for use

under the Acid Rain Program, as of the

following dates:

(i) For a unit that commenced

operation on or before January 1, 1997,

from January 1 of the year following

submission of the certification

application until the completion of the

period for the Administrator’s review; or

(ii) For a unit that commenced

operation after January 1, 1997, from the

date of submission of a certification

application for approval to use the low

mass emissions excepted methodology

under § 75.19 until the completion of

the period for the Administrator’s

review, except that the methodology

may be used retrospectively until the

date and hour that the unit commenced

operation for purposes of demonstrating

that the unit qualified to use the

methodology under § 75.19(b)(4)(iii).

(4) Disapproval of certification

applications. If the Administrator

determines that the certification

application does not demonstrate that

the unit meets the requirements of

§§ 75.19(a) and (b), the Administrator

shall issue a written notice of

disapproval of the certification

application within 120 days of receipt.

By issuing the notice of disapproval, the

provisional certification is invalidated

by the Administrator, and the data

recorded under the excepted

methodology shall not be considered

valid. The owner or operator shall

follow the procedures for loss of

certification:

(i) The owner or operator shall

substitute the following values, as

applicable, for each hour of unit

operation during the period of invalid

data specified in paragraph (a)(4)(iii) of

this section or in §§ 75.21(e)

(introductory paragraph) and

75.21(e)(1): the maximum potential

concentration of SO2, as defined in

section 2.1.1.1 of appendix A to this

part to report SO2 concentration; the

maximum potential NOX emission rate,

as defined in § 72.2 of this chapter to

report NOX emission rate; the maximum

potential flow rate, as defined in section

2.1 of appendix A to this part to report

volumetric flow; or the maximum CO2

concentration used to determine the

maximum potential concentration of

SO2 in section 2.1.1.1 of appendix A to

this part to report CO2 concentration

data. For a unit subject to a State or

federal NOX mass reduction program

where the owner or operator intends to

monitor NOX mass emissions with a

NOX pollutant concentration monitor

and a flow monitoring system,

substitute for NOX concentration using

the maximum potential concentration of

NOX, as defined in section 2.1.2.1 of

appendix A to this part, and substitute

for volumetric flow using the maximum

potential flow rate, as defined in section

2.1 of appendix A to this part. The

owner or operator shall substitute these

values until such time, date, and hour

as a continuous emission monitoring

system or excepted monitoring system,

where applicable, is installed and

provisionally certified;

(ii) The designated representative

shall submit a notification of

certification test dates, as specified in

§ 75.61(a)(1)(ii), and a new certification

application according to the procedures

in paragraph (a)(2) of this section; and

(iii) The owner or operator shall

install and provisionally certify

continuous emission monitoring

systems or excepted monitoring

systems, where applicable, two calendar

quarters from the end of the quarter in

which the unit no longer qualifies as a

low mass emissions unit.

14. Section 75.24 is amended by

revising paragraph (d) to read as

follows:

§ 75.24 Out-of-control periods.

* * * * *

(d) When the bias test indicates that

an SO2 monitor, a volumetric flow

monitor, a NOX continuous emission

monitoring system or a NOX

concentration monitoring system used

to determine NOX mass emissions, as

defined in § 75.71(a)(2), is biased low

(i.e., the arithmetic mean of the

differences between the reference

method value and the monitor or

monitoring system measurements in a

relative accuracy test audit exceed the

bias statistic in section 7 of appendix A

to this part), the owner or operator shall

adjust the monitor or continuous

emission monitoring system to

eliminate the cause of bias such that it

passes the bias test, or calculate and use

the bias adjustment factor as specified

in section 2.3.3 of appendix B to this

part and in accordance with § 75.7.

* * * * *

16. Subpart H is added to part 75 to

read as follows:
Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations 57507

Subpart H—NOX Mass Emissions

Provisions

Sec.

75.70 NOX mass emissions provisions.

75.71 Specific provisions for monitoring

NOX emission rate and heat input for the

purpose of calculating NOX mass

emissions.

75.72 Determination of NOX mass

emissions.

75.73 Recordkeeping and reporting

[Reserved].

75.74 Annual and ozone season monitoring

and reporting requirements.

75.75 Additional ozone season calculation

procedures for special circumstances.

Subpart H—NOX Mass Emissions

Provisions

§ 75.70 NOX mass emissions provisions.

(a) Applicability. The owner or

operator of a unit shall comply with the

requirements of this subpart to the

extent that compliance is required by an

applicable State or federal NOX mass

emission reduction program that

incorporates by reference, or otherwise

adopts the provisions of, this subpart.

(1) For purposes of this subpart, the

term ‘‘affected unit’’ shall mean any unit

that is subject to a State or federal NOX

mass emission reduction program

requiring compliance with this subpart,

the term ‘‘nonaffected unit’’ shall mean

any unit that is not subject to such a

program, the term ‘‘permitting

authority’’ shall mean the permitting

authority under an applicable State or

federal NOX mass emission reduction

program that adopts the requirements of

this subpart, and the term ‘‘designated

representative’’ shall mean the

responsible party under the applicable

State or federal NOX mass emission

reduction program that adopts the

requirements of this subpart.

(2) In addition, the provisions of

subparts A, C, D, E, F, and G and

appendices A through G of this part

applicable to NOX concentration, flow

rate, NOX emission rate and heat input,

as set forth and referenced in this

subpart, shall apply to the owner or

operator of a unit required to meet the

requirements of this subpart by a State

or federal NOX mass emission reduction

program. When applying these

requirements, the term ‘‘affected unit’’

shall mean any unit that is subject to a

State or federal NOX mass emission

reduction program requiring compliance

with this subpart, the term ‘‘permitting

authority’’ shall mean the permitting

authority under an applicable State or

federal NOX mass emission reduction

program that adopts the requirements of

this subpart, and the term ‘‘designated

representative’’ shall mean the

responsible party under the applicable

State or federal NOX mass emission

reduction program that adopts the

requirements of this subpart. The

requirements of this part for SO2, CO2

and opacity monitoring, recordkeeping

and reporting do not apply to units that

are subject to a State or federal NOX

mass emission reduction program only

and are not affected units with an Acid

Rain emission limitation.

(b) Compliance dates. The owner or

operator of an affected unit shall meet

the compliance deadlines established by

an applicable State or federal NOX mass

emission reduction program that adopts

the requirements of this subpart.

(c) Prohibitions. (1) No owner or

operator of an affected unit or a nonaffected unit under § 75.72(b)(2)(ii) 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 paragraph

(h) of this section.

(2) No owner or operator of an

affected unit or a non-affected unit

under § 75.72(b)(2)(ii) shall operate the

unit so as to discharge, or allow to be

discharged emissions of NOX to the

atmosphere without accounting for all

such emissions in accordance with the

applicable provisions of this part,

except as provided in § 75.74.

(3) No owner or operator of an

affected unit or a non-affected unit

under § 75.72(b)(2)(ii) 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 provisions of this

part applicable to monitoring systems

under § 75.71, except as provided in

§ 75.74.

(4) No owner or operator of an

affected unit or a non-affected unit

under § 75.72(b)(2)(ii) shall retire or

permanently discontinue use of the

continuous emission monitoring system,

any component thereof, or any other

approved emission monitoring system

under this part, except under any one of

the following circumstances:

(i) During the period that the unit is

covered by a retired unit exemption that

is in effect under the State or federal

NOX mass emission reduction program

that adopts the requirements of this

subpart;

(ii) The owner or operator is

monitoring NOX mass emissions from

the affected unit with another certified

monitoring system approved, in

accordance with the provisions of

paragraph (d) of this section; or

(iii) The designated representative

submits notification of the date of

certification testing of a replacement

monitoring system in accordance with

§ 75.61.

(d) Initial certification and

recertification procedures. (1) The

owner or operator of an affected unit

that is subject to an Acid Rain emissions

limitation shall comply with the initial

certification and recertification

procedures of this part, except that the

owner or operator shall meet any

additional requirements set forth in an

applicable State or federal NOX mass

emission reduction program that adopts

the requirements of this subpart.

(2) The owner or operator of an

affected unit that is not subject to an

Acid Rain emissions limitation shall

comply with the initial certification and

recertification procedures established by

an applicable State or federal NOX mass

emission reduction program that adopts

the requirements of this subpart. The

owner or operator of an affected unit

that is subject to an Acid Rain emissions

limitation shall comply with the initial

certification and recertification

procedures established by an applicable

State or federal NOX mass emission

reduction program that adopts the

requirements of this subpart for any

additional NOX-diluent CEMS, flow

monitors, diluent monitors or NOX

concentration monitoring system

required under the NOX mass emissions

provisions of § 75.71 or the common

stack provisions in § 75.72.

(e) Quality assurance and quality

control requirements. For units that use

continuous emission monitoring

systems to account for NOX mass

emissions, the owner or operator shall

meet the quality assurance and quality

control requirements in § 75.21 that

apply to NOX-diluent continuous

emission monitoring systems, flow

monitoring systems, NOX concentration

monitoring systems, and diluent

monitors under § 75.71. A NOX

concentration monitoring system for

determining NOX mass emissions in

accordance with § 75.71 shall meet the

same certification testing requirements,

quality assurance requirements, and

bias test requirements as are specified in

this part for an SO2 pollutant

concentration monitor. Units using

excepted methods under § 75.19 shall

meet the applicable quality assurance

requirements of that section, and units

using excepted monitoring methods

under appendix D and E to this part

shall meet the applicable quality
57508 Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations

assurance requirements of those

appendices.

(f) Missing data procedures. Except as

provided in § 75.34 and paragraph (g) of

this section, the owner or operator shall

provide substitute data from monitoring

systems required under § 75.71 for each

affected unit as follows:

(1) For an owner or operator using a

continuous emissions monitoring

system, substitute for missing data in

accordance with the missing data

procedures in subpart D of this part

whenever the unit combusts fuel and:

(i) A valid quality assured hour of

NOX emission rate data (in lb/mmBtu)

has not been measured and recorded for

a unit by a certified NOX-diluent

continuous emission monitoring system

or by an approved monitoring system

under subpart E of this part;

(ii) A valid quality assured hour of

flow data (in scfh) has not been

measured and recorded for a unit from

a certified flow monitor or by an

approved alternative monitoring system

under subpart E of this part; or

(iii) A valid quality assured hour of

heat input data (in mmBtu) has not been

measured and recorded for a unit from

a certified flow monitor and a certified

diluent (CO2 or O2) monitor or by an

approved alternative monitoring system

under subpart E of this part or by an

accepted monitoring system under

appendix D to this part, where heat

input is required either for calculating

NOX mass or allocating allowances

under the applicable State or federal

NOX mass emission reduction program

that adopts the requirements of this

subpart; or

(iv) A valid, quality-assured hour of

NOX concentration data (in ppm) has

not been measured and recorded by a

certified NOX concentration monitoring

system, or by an approved alternative

monitoring method under subpart E of

this part, where the owner or operator

chooses to use a NOX concentration

monitoring system with a volumetric

flow monitor, and without a diluent

monitor, to calculate NOX mass

emissions. The initial missing data

procedures for determining monitor

data availability and the standard

missing data procedures for a NOX

concentration monitoring system shall

be the same as the procedures specified

for a NOX-diluent continuous emission

monitoring system under §§ 75.31, 75.32

and 75.33, except that the phrase ‘‘NOX

concentration monitoring system’’ shall

be substituted for the phrase ‘‘NOX

continuous emission monitoring

system’’, the phrase ‘‘NOX

concentration’’ shall be substituted for

‘‘NOX emission rate’; and the phrase

‘‘maximum potential NOX

concentration, as defined in section

2.1.2.1 of appendix A of this part’’ shall

be substituted for the phrase ‘‘maximum

potential NOX emission rate, as defined

in § 72.2 of this chapter’’.

(2) For an owner or operator using an

excepted monitoring system under

appendix D or E of this part, substitute

for missing data in accordance with the

missing data procedures in section 2.4

of appendix D to this part or in section

2.5 of appendix E to this part whenever

the unit combusts fuel and:

(i) A valid, quality-assured hour of

fuel flow rate data has not been

measured and recorded by a certified

fuel flowmeter that is part of an

excepted monitoring system under

appendix D or E of this part; or

(ii) A fuel sample value for gross

calorific value, or if necessary, density

or specific gravity, from a sample taken

an analyzed in accordance with

appendix D of this part is not available;

or

(iii) A valid, quality-assured hour of

NOX emission rate data has not been

obtained according to the procedures

and specifications of appendix E to this

part.

(g) Reporting data prior to initial

certification. If the owner or operator of

an affected unit has not successfully

completed all certification tests required

by the State or federal NOX mass

emission reduction program that adopts

the requirements of this subpart by the

applicable date required by that

program, he or she shall determine,

record and report hourly data prior to

initial certification using one of the

following procedures, consistent with

the monitoring equipment to be

certified:

(1) For units that the owner or

operator intends to monitor for NOX

mass emissions using NOX emission rate

and heat input, the maximum potential

NOX emission rate and the maximum

potential hourly heat input of the unit,

as defined in § 72.2 of this chapter.

(2) For units that the owner or

operator intends to monitor for NOX

mass emissions using a NOX

concentration monitoring system and a

flow monitoring system, the maximum

potential concentration of NOX and the

maximum potential flow rate of the unit

under section 2.1 of Appendix A of this

part;

(3) For any unit, the reference

methods under § 75.22 of this part.

(4) For any unit using the low mass

emission excepted monitoring

methodology under § 75.19, the

procedures in paragraphs (g)(1) or (2) of

this section.

(5) Any unit using the procedures in

paragraph (g)(2) of this section that is

required to report heat input for

purposes of allocating allowances shall

also report the maximum potential

hourly heat input of the unit, as defined

in § 72.2 of this chapter.

(h) Petitions. (1) The designated

representative of an affected unit that is

subject to an Acid Rain emissions

limitation may submit a petition to the

Administrator requesting an alternative

to any requirement of this subpart. Such

a petition shall meet the requirements of

§ 75.66 and any additional requirements

established by an applicable State or

federal NOX mass emission reduction

program that adopts the requirements of

this subpart. Use of an alternative to any

requirement of this subpart is in

accordance with this subpart and with

such State or federal NOX mass

emission reduction program only to the

extent that the petition is approved by

the Administrator, in consultation with

the permitting authority.

(2) Notwithstanding paragraph (h)(1)

of this section, petitions requesting an

alternative to a requirement concerning

any additional CEMS required solely to

meet the common stack provisions of

§ 75.72 shall be submitted to the

permitting authority and the

Administrator and shall be governed by

paragraph (h)(3)(ii) of this section. Such

a petition shall meet the requirements of

§ 75.66 and any additional requirements

established by an applicable State or

federal NOX mass emission reduction

program that adopts the requirements of

this subpart.

(3)(i) The designated representative of

an affected unit that is not subject to an

Acid Rain emissions limitation may

submit a petition to the permitting

authority and the Administrator

requesting an alternative to any

requirement of this subpart. Such a

petition shall meet the requirements of

§ 75.66 and any additional requirements

established by an applicable State or

federal NOX mass emission reduction

program that adopts the requirements of

this subpart.

(ii) Use of an alternative to any

requirement of this subpart is in

accordance with this subpart only to the

extent that it is approved by the

Administrator and by the permitting

authority if required by an applicable

State or federal NOX mass emission

reduction program that adopts the

requirements of this subpart.

§ 75.71 Specific provisions for monitoring

NOX emission rate and heat input for the

purpose of calculating NOX mass

emissions.

(a) Coal-fired units. The owner or

operator of a coal-fired affected unit

shall either:
Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations 57509

(1) Meet the general operating

requirements in § 75.10 for a NOXdiluent continuous emission monitoring

system (consisting of a NOX pollutant

concentration monitor, an O2- or CO2-

diluent gas monitor, and a data

acquisition and handling system) to

measure NOX emission rate and for a

flow monitoring system and an O2- or

CO2-diluent gas monitor to measure heat

input, except as provided in accordance

with subpart E of this part; or

(2) Meet the general operating

requirements in § 75.10 for a NOX

concentration monitoring system

(consisting of a NOX pollutant

concentration monitor and a data

acquisition and handling system) to

measure NOX concentration and for a

flow monitoring system. In addition, if

heat input is required to be reported

under the applicable State or federal

NOX mass emission reduction program

that adopts the requirements of this

subpart, the owner or operator also must

meet the general operating requirements

for a flow monitoring system and an O2-

or CO2-diluent gas monitor to measure

heat input, or, if applicable, use the

procedures in appendix D to this part.

These requirements must be met, except

as provided in accordance with subpart

E of this part.

(b) Moisture correction. If a correction

for the stack gas moisture content is

needed to properly calculate the NOX

emission rate in lb/mmBtu (i.e., if the

NOX pollutant concentration monitor

measures on a different moisture basis

from the diluent monitor) or NOX mass

emissions in tons (i.e., if the NOX

concentration monitoring system or

diluent monitor measures on a different

moisture basis from the flow rate

monitor), the owner or operator of an

affected unit shall account for the

moisture content of the flue gas on a

continuous basis in accordance with

§ 75.11(b) except that the term ‘‘SO2’’

shall be replaced by the term ‘‘NOX’.

(c) Gas-fired nonpeaking units or oilfired nonpeaking units. The owner or

operator of an affected unit that, based

on information submitted by the

designated representative in the

monitoring plan, qualifies as a gas-fired

or oil-fired unit but not as a peaking

unit, as defined in § 72.2 of this chapter,

shall either:

(1) Meet the requirements of

paragraph (a) of this section and, if

applicable, paragraph (b) of this section;

or

(2) Meet the general operating

requirements in § 75.10 for a NOXdiluent continuous emission monitoring

system, except as provided in

accordance with subpart E of this part,

and use the procedures specified in

appendix D to this part for determining

hourly heat input. However, the heat

input apportionment provisions in

section 2.1.2 of appendix D to this part

shall not be used to meet the NOX mass

reporting provisions of this subpart,

except as provided in § 75.72(a); or

(3) Meet the requirements of the low

mass emission excepted methodology

under paragraph (e)(2) of this section

and under § 75.19, if applicable.

(d) Gas-fired or oil-fired peaking

units. The owner or operator of an

affected unit that qualifies as a peaking

unit and as either gas-fired or oil-fired,

as defined in § 72.2 of this chapter,

based on information submitted by the

designated representative in the

monitoring plan, shall either:

(1) Meet the requirements of

paragraph (c) of this section; or

(2) Use the procedures in appendix D

to this part for determining hourly heat

input and the procedures specified in

appendix E to this part for estimating

hourly NOX emission rate. However, the

heat input apportionment provisions in

section 2.1.2 of appendix D to this part

shall not be used to meet the NOX mass

reporting provisions of this subpart

except for units using an excepted

monitoring system under appendix E to

this part and except as provided in

§ 75.72(a). In addition, if after

certification of an excepted monitoring

system under appendix E to this part, a

unit’s operations exceed a capacity

factor of 20.0 percent in any calender

year or exceed a capacity factor of 10.0

percent averaged over three years, the

owner or operator shall meet the

requirements of paragraph (c) of this

section or, if applicable, paragraph (e) of

this section, by no later than December

31 of the following calender year.

(e) Low mass emissions units.

Notwithstanding the requirements of

paragraphs (c) and (d) of this section,

the owner or operator of an affected unit

that qualifies as a low mass emissions

unit under § 75.19(a) shall comply with

one of the following:

(1) Meet the applicable requirements

specified in paragraphs (c) or (d) of this

section; or

(2) Use the low mass emissions

excepted methodology in § 75.19(c) for

estimating hourly emission rate, hourly

heat input, and hourly NOX mass

emissions.

(f) Other units. The owner or operator

of an affected unit that combusts wood,

refuse, or other materials shall comply

with the monitoring provisions

specified in paragraph (a) of this section

and, where applicable, paragraph (b) of

this section.

§ 75.72 Determination of NOX mass

emissions.

Except as provided in paragraphs (e)

and (f) of this section, the owner or

operator of an affected unit shall

calculate hourly NOX mass emissions

(in lbs) by multiplying the hourly NOX

emission rate (in lbs/mmBtu) by the

hourly heat input (in mmBtu/hr) and

the hourly operating time (in hr). The

owner or operator shall also calculate

quarterly and cumulative year-to-date

NOX mass emissions and cumulative

NOX mass emissions for the ozone

season (in tons) by summing the hourly

NOX mass emissions according to the

procedures in section 8 of appendix F

to this part.

(a) Unit utilizing common stack with

other affected unit(s). When an affected

unit utilizes a common stack with one

or more affected units, but no

nonaffected units, the owner or operator

shall either:

(1) Record the combined NOX mass

emissions for the units exhausting to the

common stack, install, certify, operate,

and maintain a NOX-diluent continuous

emissions monitoring system in the

common stack, and either:

(i) Install, certify, operate, and

maintain a flow monitoring system at

the common stack. The owner or

operator also shall provide heat input

values for each unit, either by

monitoring each unit individually using

a flow monitor and a diluent monitor or

by apportioning heat input according to

the procedures in § 75.16(e)(5); or

(ii) If any of the units using the

common stack are eligible to use the

procedures in appendix D to this part,

(A) Use the procedures in appendix D

to this part to determine heat input for

that unit; and

(B) Install, certify, operate, and

maintain a flow monitoring system in

the duct to the common stack for each

remaining unit; or

(2) Install, certify, operate, and

maintain a NOX-diluent continuous

emissions monitoring system in the duct

to the common stack from each unit and

either:

(i) Install, certify, operate, and

maintain a flow monitoring system in

the duct to the common stack from each

unit; or

(ii) For any unit using the common

stack and eligible to use the procedures

in appendix D to this part,

(A) Use the procedures in appendix D

to determine heat input for that unit;

and

(B) Install, certify, operate, and

maintain a flow monitoring system in

the duct to the common stack for each

remaining unit.
57510 Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations

(b) Unit utilizing common stack with

nonaffected unit(s). When one or more

affected units utilizes a common stack

with one or more nonaffected units, the

owner or operator shall either:

(1) Install, certify, operate, and

maintain a NOX-diluent continuous

emission monitoring system in the duct

to the common stack from each affected

unit; and

(i) Install, certify, operate, and

maintain a flow monitoring system in

the duct to the common stack from each

affected unit; or

(ii) For any affected unit using the

common stack and eligible to use the

procedures in appendix D to this part,

(A) Use the procedures in appendix D

to determine heat input for that unit;

however, the heat input apportionment

provisions in section 2.1.2 of appendix

D to this part shall not be used to meet

the NOX mass reporting provisions of

this subpart; and

(B) Install, certify, operate, and

maintain a flow monitoring system in

the duct to the common stack for each

remaining affected unit that exhausts to

the common stack; or

(2) Install, certify, operate, and

maintain a NOX-diluent continuous

emission monitoring system in the

common stack; and

(i) Designate the nonaffected units as

affected units in accordance with the

applicable State or federal NOX mass

emissions reduction program and meet

the requirements of paragraph (a)(1) of

this section; or

(ii) Install, certify, operate, and

maintain a flow monitoring system in

the common stack and a NOX-diluent

continuous emission monitoring system

in the duct to the common stack from

each nonaffected unit. The designated

representative shall submit a petition to

the permitting authority and the

Administrator to allow a method of

calculating and reporting the NOX mass

emissions from the affected units as the

difference between NOX mass emissions

measured in the common stack and NOX

mass emissions measured in the ducts

of the nonaffected units, not to be

reported as an hourly value less than

zero. The permitting authority and the

Administrator may approve such a

method whenever the designated

representative demonstrates, to the

satisfaction of the permitting authority

and the Administrator, that the method

ensures that the NOX mass emissions

from the affected units are not

underestimated. In addition, the owner

or operator shall also either:

(A) Install, certify, operate, and

maintain a flow monitoring system in

the duct from each nonaffected unit or,

(B) For any nonaffected unit

exhausting to the common stack and

otherwise eligible to use the procedures

in appendix D to this part, determine

heat input using the procedures in

appendix D for that unit. However, the

heat input apportionment provisions in

section 2.1.2 of appendix D to this part

shall not be used to meet the NOX mass

reporting provisions of this subpart. For

any remaining nonaffected unit that

exhausts to the common stack, install,

certify, operate, and maintain a flow

monitoring system in the duct to the

common stack; or

(iii) Install a flow monitoring system

in the common stack and record the

combined emissions from all units as

the combined NOX mass emissions for

the affected units for recordkeeping and

compliance purposes; or

(iv) Submit a petition to the

permitting authority and the

Administrator to allow use of a method

for apportioning NOX mass emissions

measured in the common stack to each

of the units using the common stack and

for reporting the NOX mass emissions.

The permitting authority and the

Administrator may approve such a

method whenever the designated

representative demonstrates, to the

satisfaction of the permitting authority

and the Administrator, that the method

ensures that the NOX mass emissions

from the affected units are not

underestimated.

(c) Unit with bypass stack. Whenever

any portion of the flue gases from an

affected unit can be routed to avoid the

installed NOX-diluent continuous

emissions monitoring system or NOX

concentration monitoring system, the

owner and operator shall either:

(1) Install, certify, operate, and

maintain a NOX-diluent continuous

emissions monitoring system and a flow

monitoring system on the bypass flue,

duct, or stack gas stream and calculate

NOX mass emissions for the unit as the

sum of the emissions recorded by all

required monitoring systems; or

(2) Monitor NOX mass emissions on

the bypass flue, duct, or stack gas stream

using the reference methods in

§ 75.22(b) for NOX concentration, flow,

and diluent, or NOX concentration and

flow, and calculate NOX mass emissions

for the unit as the sum of the emissions

recorded by the installed monitoring

systems on the main stack and the

emissions measured by the reference

method monitoring systems.

(d) Unit with multiple stacks.

Notwithstanding § 75.17(c), when the

flue gases from a affected unit discharge

to the atmosphere through more than

one stack, or when the flue gases from

a unit subject to a NOX mass emission

reduction program utilize two or more

ducts feeding into two or more stacks

(which may include flue gases from

other affected or nonaffected unit(s)), or

when the flue gases from an affected

unit utilize two or more ducts feeding

into a single stack and the owner or

operator chooses to monitor in the ducts

rather than in the stack, the owner or

operator shall either:

(1) Install, certify, operate, and

maintain a NOX-diluent continuous

emission monitoring system and a flow

monitoring system in each duct feeding

into the stack or stacks and determine

NOX mass emissions from each affected

unit using the stack or stacks as the sum

of the NOX mass emissions recorded for

each duct; or

(2) Install, certify, operate, and

maintain a NOX-diluent continuous

emissions monitoring system and a flow

monitoring system in each stack, and

determine NOX mass emissions from the

affected unit using the sum of the NOX

mass emissions recorded for each stack,

except that where another unit also

exhausts flue gases to one or more of the

stacks, the owner or operator shall also

comply with the applicable

requirements of paragraphs (a) and (b) of

this section to determine and record

NOX mass emissions from the units

using that stack; or

(3) If the unit is eligible to use the

procedures in appendix D to this part,

install, certify, operate, and maintain a

NOX-diluent continuous emissions

monitoring system in one of the ducts

feeding into the stack or stacks and use

the procedures in appendix D to this

part to determine heat input for the unit,

provided that:

(i) There are no add-on NOX controls

at the unit;

(ii) The unit is not capable of emitting

solely through an unmonitored stack

(e.g., has no dampers); and

(iii) The owner or operator of the unit

demonstrates to the satisfaction of the

permitting authority and the

Administrator that the NOX emission

rate in the monitored duct or stack is

representative of the NOX emission rate

in each duct or stack.

(e) Units using a NOX concentration

monitoring system and a flow

monitoring system to determine NOX

mass. The owner or operator may use a

NOX concentration monitoring system

and a flow monitoring system to

determine NOX mass emissions in

paragraphs (a) through (d) of this section

(in place of a NOX-diluent continuous

emission monitoring system and a flow

monitoring system). When using this

approach, calculate NOX mass according

to sections 8.2 and 8.3 in appendix F of

this part. In addition, if an applicable
Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations 57511

State or federal NOX mass reduction

program requires determination of a

unit’s heat input, the owner or operator

must either:

(1) Install, certify, operate, and

maintain a CO2 or O2 diluent monitor in

the same location as each flow

monitoring system. In addition, the

owner or operator must provide heat

input values for each unit utilizing a

common stack by either:

(i) Apportion heat input from the

common stack to each unit according to

§ 75.16(e)(5), where all units utilizing

the common stack are affected units, or

(ii) Measure heat input from each

affected unit, using a flow monitor and

a CO2 or O2 diluent monitor in the duct

from each affected unit; or

(2) For units that are eligible to use

appendix D to this part, use the

procedures in appendix D to this part to

determine heat input for the unit.

However, the use of a fuel flowmeter in

a common pipe header and the

provisions of sections 2.1.2.1 and 2.1.2.2

of appendix D of this part are not

applicable to any unit that is using the

provisions of this subpart to monitor,

record, and report NOX mass emissions

under a State or federal NOX mass

emission reduction program and that

shares a common pipe or a common

stack with a nonaffected unit.

(f) Units using the low mass emitter

excepted methodology under § 75.19.

For units that are using the low mass

emitter excepted methodology under

§ 75.19, calculate ozone season NOX

mass emissions by summing all of the

hourly NOX mass emissions in the

ozone season, as determined under

paragraph § 75.19(c)(4)(ii)(A) of this

section, divided by 2000 lb/ton.

(g) Procedures for apportioning heat

input to the unit level. If the owner or

operator of a unit using the common

stack monitoring provisions in

paragraphs (a) or (b) of this section does

not monitor and record heat input at the

unit level and the owner or operator is

required to do so under an applicable

State or federal NOX mass emission

reduction program, the owner or

operator should apportion heat input

from the common stack to each unit

according to § 75.16(e)(5).

§ 75.73 Recordkeeping and reporting.

[Reserved]

§ 75.74 Annual and ozone season

monitoring and reporting requirements.

(a) Annual monitoring requirement.

(1) The owner or operator of an affected

unit subject both to an Acid Rain

emission limitation and to a State or

federal NOX mass reduction program

that adopts the provisions of this part

must meet the requirements of this part

during the entire calendar year.

(2) The owner or operator of an

affected unit subject to a State or federal

NOX mass reduction program that

adopts the provisions of this part and

that requires monitoring and reporting

of hourly emissions on an annual basis

must meet the requirements of this part

during the entire calendar year.

(b) Ozone season monitoring

requirements. The owner or operator of

an affected unit that is not required to

meet the requirements of this subpart on

an annual basis under paragraph (a) of

this section may either:

(1) Meet the requirements of this

subpart on an annual basis; or

(2) Meet the requirements of this part

during the ozone season, except as

specified in paragraph (c) of this

section.

(c) If the owner or operator of an

affected unit chooses to meet the

requirements of this subpart on less

than an annual basis in accordance with

paragraph (b)(2) of this section, then:

(1) The owner or operator of a unit

that uses continuous emissions

monitoring systems to meet any of the

requirements of this subpart must

perform recertification testing of all

continuous emission monitoring

systems under § 75.20(b). If the owner or

operator has not successfully completed

all recertification tests by the first hour

of unit operation during the ozone

season each year, the owner or operator

must substitute for data following the

procedures of § 75.20(b).

(2) The owner or operator is required

to operate and maintain continuous

emission monitoring systems and

perform quality assurance and quality

control procedures under § 75.21 and

appendix B of this part each year from

the time the continuous emission

monitoring system is initially certified

or is recertified under paragraph (c)(1)

of this section through September 30.

Records related to the quality assurance/

quality control program must be kept in

a form suitable for inspection on a yearround basis.

(3) The owner or operator of a unit

using the procedures in appendix D of

this part to determine heat input is

required to operate or maintain fuel

flowmeters only during the ozone

season, except that for purposes of

determining the deadline for the next

periodic quality assurance test on the

fuel flowmeter, the owner or operator

shall count all quarters during the year

when the fuel flowmeter is used, not

just quarters in the ozone season. The

owner or operator shall record and the

designated representative shall report

the number of quarters when a fuel is

combusted for each fuel flowmeter.

(4) The owner or operator of a unit

using the procedures in appendix D of

this part to determine heat input is only

required to sample fuel during the

ozone season, except that:

(i) The owner or operator of a dieselfired unit that performs sampling from

the fuel storage tank upon delivery must

sample the tank between the date and

hour of the most recent delivery before

the first date and hour that the unit

operates in the ozone season and the

first date and hour that the unit operates

in the ozone season.

(ii) The owner or operator of a dieselfired unit that performs sampling upon

delivery from the delivery vehicle must

ensure that all shipments received

during the calendar year are sampled.

(iii) The owner or operator of a unit

that performs sampling on each day the

unit combusts fuel oil or that performs

oil sampling continuously must sample

the fuel oil starting on the first day the

unit operates during the ozone season.

The owner or operator then shall use

that sampled value for all hours of

combustion during the first day of unit

operation, continuing until the date and

hour of the next sample.

(5) The owner or operator is required

to record and report the hourly data

required by this subpart for the longer

of:

(i) The period of time that the owner

or operator of the unit is required to

perform the quality assurance and

quality control procedures of § 75.21

and appendix B of this part under

paragraph (c)(2) of this section; or

(ii) The period of time of May 1

through September 30.

(6) The owner or operator shall use

quality-assured data, in accordance with

paragraph (c)(2) or (c)(3) of this section,

in the substitute data procedures under

subpart D of this part and section 2.4 of

appendix D of this part.

(i) The lookback periods (e.g., 2160

quality-assured monitor operating hours

for a NOX-diluent continuous emission

monitoring system, a NOX concentration

monitoring system, or a flow monitoring

system) used to calculate missing data

must include only data from periods

when the monitors were quality assured

under paragraph (c)(2) or (c)(3) of this

section.

(ii) If the NOX emission rate or NOX

concentration of the unit was

consistently lower in the previous ozone

season because the unit combusted a

fuel that produces less NOX than the

fuel currently being combusted or

because the unit’s add-on emission

controls are not operating properly, then

the owner or operator shall not use the
57512 Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations

missing data procedures of §§ 75.31

through 75.33. Instead, the owner or

operator shall substitute the maximum

potential NOX emission rate, as defined

in § 72.2 of this chapter, from a NOXdiluent continuous emission monitoring

system, or the maximum potential

concentration of NOX, as defined in

section 2.1.2.1 of appendix A to this

part, from a NOX concentration

monitoring system. The owner or

operator shall substitute these

maximum potential values for each hour

of missing NOX data, from completion

of recertification testing until the

earliest of:

(A) 720 quality-assured monitor

operating hours after the completion of

recertification testing (not to go beyond

September 30 of that ozone season), or

(B) For a unit that changed fuels, the

first hour when the unit combusts a fuel

that produces the same or less NOX than

the fuel combusted in the previous

ozone season, or

(C) For a unit with add-on emission

controls that are not operating properly,

the first hour when the add-on emission

controls operate properly.

(7) The owner or operator of a unit

with NOX add-on emission controls or

a unit capable of combusting more than

one fuel shall keep records during ozone

season in a form suitable for inspection

to demonstrate that the typical NOX

emission rate or NOX concentration

during the prior ozone season(s)

included in the missing data lookback

period is representative of the ozone

season in which missing data are

substituted and that use of the missing

data procedures will not systematically

underestimate NOX mass emissions.

These records shall include:

(i) For units that can combust more

than one fuel, the fuel or fuels

combusted each hour; and

(ii) For units with add-on emission

controls, the range of operating

parameters for add-on emission

controls, as described in § 75.34(a) and

information for verifying proper

operation of the add-on emission

controls, as described in § 75.34(d).

(8) The designated representative

shall certify with each quarterly report

that NOX emission rate values or NOX

concentration values substituted for

missing data under subpart D of this

part are calculated using only values

from an ozone season, that substitute

values measured during the prior ozone

season(s) included in the missing data

lookback period are representative of

the ozone season in which missing data

are substituted, and that NOX emissions

are not systematically underestimated.

(9) Units may qualify to use the low

mass emission excepted monitoring

methodology in § 75.19 on an ozone

season basis. In order to be allowed to

use this methodology, a unit may not

emit more than 25 tons of NOX per

ozone season. The owner or operator of

the unit shall meet the requirements of

§ 75.19, with the following exceptions:

(i) The phrase ‘‘50 tons of NOX

annually’’ shall be replaced by the

phrase ‘‘25 tons of NOX during the

ozone season.’’

(ii) If any low mass emission unit fails

to provide a demonstration that its

ozone season NOX mass emissions are

less than 25 tons, than the unit is

disqualified from using the

methodology. The owner or operator

must install and certify any equipment

needed to ensure that the unit is

monitoring using an acceptable

methodology by May 1 of the following

year.

(10) Units may qualify to use the

optional NOX mass emissions

estimation protocol for gas-fired peaking

units and oil-fired peaking units in

appendix E to this part on an ozone

season basis. In order to be allowed to

use this methodology, the unit must

meet the definition of peaking unit in

§ 72.2 of this part, except that the word

‘‘calender year’’ shall be replaced by the

word ‘‘ozone season’’ and the word

annual in the definition of the term

‘‘capacity factor’’ in § 72.2 of this part,

shall be replaced by the word ‘‘ozone

season’’.

§ 75.75 Additional ozone season

calculation procedures for special

circumstances.

(a) The owner or operator of a unit

that is required to calculate ozone

season heat input for purposes of

providing data needed for determining

allocations, shall do so by summing the

unit’s hourly heat input determined

according to the procedures in this part

for all hours in which the unit operated

during the ozone season.

(b) The owner or operator of a unit

that is required to determine ozone

season NOX emission rate (in lbs/

mmBtu) shall do so by dividing ozone

season NOX mass emissions(in lbs)

determined in accordance with this

subpart, by heat input determined in

accordance with paragraph (a) of this

section.

17. Section 3 of appendix A to part 75

is amended by revising the title of

section 3.3.2 and by adding and

reserving section 3.3.6, by adding new

section 3.3.7 and by revising section

3.4.1 to read as follows:

APPENDIX A TO PART 75—

SPECIFICATIONS AND TEST

PROCEDURES

* * * * *

3. PERFORMANCE SPECIFICATIONS

* * * * *

3.3.2 RELATIVE ACCURACY FOR NOX

DILUENT CONTINUOUS EMISSION

MONITORING SYSTEMS

* * * * *

3.3.6 [Reserved]

3.3.7 RELATIVE ACCURACY FOR NOX

CONCENTRATION MONITORING

SYSTEMS

The following requirement applies only to

NOX concentration monitoring systems (i.e.,

NOX pollutant concentration monitors) that

are used to determine NOX mass emissions,

where the owner or operator elects to

monitor and report NOX mass emissions

using a NOX concentration monitoring

system and a flow monitoring system.

The relative accuracy for NOX

concentration monitoring systems shall not

exceed 10.0 percent.

* * * * *

3.4.1 SO2 POLLUTANT

CONCENTRATION MONITORS, NOX

CONCENTRATION MONITORING

SYSTEMS AND NOX-DILUENT

CONTINUOUS EMISSION MONITORING

SYSTEMS

SO2 pollutant concentration monitors and

NOX emission rate continuous emissions

monitoring systems shall not be biased low

as determined by the test procedure in

section 7.6 of this appendix. NOX

concentration monitoring systems used to

determine NOX mass emissions, as defined in

§ 75.71, shall not be biased low as

determined by the test procedure in section

7.6 of this appendix. The bias specification

applies to all SO2 pollutant concentration

monitors, including those measuring an

average SO2 concentration of 250.0 ppm or

less, and to all NOX-diluent continuous

emission monitoring systems, including

those measuring an average NOX emission

rate of 0.20 lb/mmBtu or less.

* * * * *

18. Section 6 of appendix A to part 75

is amended by revising the first

sentence of the introductory text of

section 6.5 and by adding a new

sentence after the first sentence, to read

as follows:

* * * * *

6.5 Relative Accuracy and Bias Tests

Perform relative accuracy test audits for

each CO2 and SO2 pollutant concentration

monitor; each NOX concentration monitoring

system used to determine NOX mass

emissions; each O2 monitor used to calculate

heat input or CO2 concentration; each SO2-

diluent continuous emission monitoring

system (lb/mmBtu) used by units with a

qualifying Phase I technology for the period

during which the units are required to

monitor SO2 emission removal efficiency,

from January 1, 1997 through December 31,

1999; each flow monitor; and each NOXdiluent continuous emission monitoring

system. Perform relative accuracy test audits

for each NOX concentration monitoring

system used to determine NOX mass

emissions, as defined in § 75.71(a)(2), using

the same general procedures as for CO2 and
Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations 57513

SO2 pollutant concentration monitors;

however, use the reference methods for NOX

concentration listed in section 6.5.10 of this

appendix. * * *

* * * * *

19. Section 7 of appendix A is

amended by revising the introductory

text of section 7.6 and by adding three

sentences to the end of section 7.6.5 to

read as follows:

* * * * *

7.6 Bias Test and Adjustment Factor

Test the relative accuracy test audit data

sets for bias for SO2 pollutant concentration

monitors; flow monitors; NOX concentration

monitoring systems used to determine NOX

mass emissions, as defined in § 75.71(a)(2);

and NOX-diluent continuous emission

monitoring systems using the procedures

outlined below.

* * * * *

7.6.5 Bias Adjustment

* * * In addition, use the adjusted NOX

concentration and flow rate values in

computing substitution values in the missing

data procedure, as specified in subpart D of

this part, and in reporting the NOX

concentration and the flow rate when used to

calculate NOX mass emissions, as specified

in subpart H of this part. Do not use an

adjusted NOX concentration value to

calculate NOX emission rate using Equations

F–5 or F–6 of Appendix F of this part. When

monitoring NOX emission rate and heat

input, use the adjusted NOX emission rate

and flow rate values in computing

substitution values in the missing data

procedure, as specified in subpart D of this

part, and in reporting the NOX emission rate

and the heat input.

* * * * *

20. Appendix C to part 75 is amended

by revising sections 2.1, 2.2.2, 2.2.3,

2.2.5, and 2.2.6 to read as follows:

APPENDIX C TO PART 75—MISSING

DATA ESTIMATION PROCEDURES

* * * * *

2.1 Applicability

This procedure is applicable for data from

all affected units for use in accordance with

the provisions of this part to provide

substitute data for volumetric flow rate (scfh),

NOX emission rate (in lb/mmBtu), and NOX

concentration data (in ppm) from NOX

concentration monitoring systems used to

determine NOX mass emissions.

2.2 Procedure

2.2.1 * * *

2.2.2 Beginning with the first hour of unit

operation after installation and certification

of the flow monitor or the NOX continuous

emission monitoring system (or a NOX

concentration monitoring system used to

determine NOX mass emissions, as defined in

§ 75.71, for each hour of unit operation

record a number, 1 through 10 (or 1 through

20 for flow at common stacks), that identifies

the operating load range corresponding to the

integrated hourly gross load of the unit(s)

recorded for each unit operating hour.

2.2.3 Beginning with the first hour of unit

operation after installation and certification

of the flow monitor or the NOX continuous

emission monitoring system (or a NOX

concentration monitoring system used to

determine NOX mass emissions, as defined in

§ 75.71 and continuing thereafter, the data

acquisition and handling system must be

capable of calculating and recording the

following information for each unit operating

hour of missing flow or NOX data within

each identified load range during the shorter

of: (1) the previous 2,160 quality assured

monitor operating hours (on a rolling basis),

or (2) all previous quality assured monitor

operating hours.

2.2.3.1 Average of the hourly flow rates

reported by a flow monitor, in scfh.

2.2.3.2 The 90th percentile value of

hourly flow rates, in scfh.

2.2.3.3 The 95th percentile value of

hourly flow rates, in scfh.

2.2.3.4 The maximum value of hourly

flow rates, in scfh.

2.2.3.5 Average of the hourly NOX

emission rate, in lb/mmBtu, reported by a

NOX continuous emission monitoring

system.

2.2.3.6 The 90th percentile value of

hourly NOX emission rates, in lb/mmBtu.

2.2.3.7 The 95th percentile value of

hourly NOX emission rates, in lb/mmBtu.

2.2.3.8 The maximum value of hourly

NOX emission rates, in lb/mmBtu.

2.2.3.9 Average of the hourly NOX

pollutant concentration, in ppm, reported by

a NOX concentration monitoring system used

to determine NOX mass emissions, as defined

in § 75.71.

2.2.3.10 The 90th percentile value of

hourly NOX pollutant concentration, in ppm.

2.2.3.11 The 95th percentile value of

hourly NOX pollutant concentration, in ppm.

2.2.3.12 The maximum value of hourly

NOX pollutant concentration, in ppm.

2.2.4 * * *

2.2.5 When a bias adjustment is necessary

for the flow monitor or the NOX continuous

emission monitoring system (or the NOX

concentration monitoring system used to

determine NOX mass emissions, as defined in

§ 75.71), apply the adjustment factor to all

monitor or continuous emission monitoring

system data values placed in the load ranges.

2.2.6 Use the calculated monitor or

monitoring system data averages, maximum

values, and percentile values to substitute for

missing flow rate and NOX emission rate data

(and where applicable, NOX concentration

data) according to the procedures in subpart

D of this part.

* * * * *

21. Section 2 of appendix D to part 75

is amended by revising the introductory

text of section 2.1.2 to read as follows:

APPENDIX D TO PART 75—OPTIONAL SO2

EMISSIONS DATA PROTOCOL FOR GASFIRED AND OIL-FIRED UNITS

* * * * *

2.1.2 Install and use fuel flowmeters

meeting the requirements of this appendix in

a pipe going to each unit, or install and use

a fuel flowmeter in a common pipe header

(i.e., a pipe carrying fuel for multiple units).

However, the use of a fuel flowmeter in a

common pipe header and the provisions of

sections 2.1.2.1 and 2.1.2.2 of this appendix

are not applicable to any unit that is using

the provisions of subpart H of this part to

monitor, record, and report NOX mass

emissions under a State or federal NOX mass

emission reduction program, except as

provided in § 75.72(a) for units with a NOX

CEMS installed in a common stack or except

as provided for units monitored with an

excepted monitoring system under appendix

E to this part. For all other units, if the fuel

flowmeter is installed in a common pipe

header, do one of the following:

* * * * *

22. Section 8 of appendix F to part 75

is added to read as follows:

APPENDIX F TO PART 75—CONVERSION

PROCEDURES

* * * * *

8. Procedures for NOX Mass Emissions

The owner or operator of a unit that is

required to monitor, record, and report NOX

mass emissions under a State or federal NOX

mass emission reduction program must use

the procedures in section 8.1 to account for

hourly NOX mass emissions, and the

procedures in section 8.2 to account for

quarterly, seasonal, and annual NOX mass

emissions to the extent that the provisions of

subpart H of this part are adopted as

requirements under such a program.

8.1 Use the following procedures to

calculate hourly NOX mass emissions in lbs

for the hour using hourly NOX emission rate

and heat input.

8.1.1 If both NOX emission rate and heat

input are monitored at the same unit or stack

level (e.g, the NOX emission rate value and

heat input value both represent all of the

units exhausting to the common stack), use

the following equation:

M E HI t Eq NO NO h h X h X h ( ) ( ) = ( . F-24)

where:

M(NOx)h = NOX mass emissions in lbs for the

hour.

E(NOx)h = Hourly average NOX emission rate

for hour h, lb/mmBtu, from section 3 of

this appendix, from method 19 of

appendix A to part 60 of this chapter, or

from section 3.3 of appendix E to this

part. (Include bias-adjusted NOX

emission rate values, where the bias-test

procedures in appendix A to this part

shows a bias-adjustment factor is

necessary.)

HIh = Hourly average heat input rate for hour

h, mmBtu/hr. (Include bias-adjusted flow

rate values, where the bias-test

procedures in appendix A to this part

shows a bias-adjustment factor is

necessary.)
57514 Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations

th = Monitoring location operating time for

hour h, in hours or fraction of an hour

(in equal increments that can range from

one hundredth to one quarter of an hour,

at the option of the owner or operator).

If the combined NOX emission rate and

heat input are monitored for all of the

units in a common stack, the monitoring

location operating time is equal to the

total time when any of those units was

exhausting through the common stack.

8.1.2 If NOX emission rate is measured at

a common stack and heat input is measured

at the unit level, sum the hourly heat inputs

at the unit level according to the following

formula:

HI

HI t

t CS Eq F

u u

u

p

CS

= =

∑

1 ( . ) -25

where:

HICS = Hourly average heat input rate for

hour h for the units at the common stack,

mmBtu/hr.

tCS = Common stack operating time for hour

h, in hours or fraction of an hour (in

equal increments that can range from one

hundredth to one quarter of an hour, at

the option of the owner or operator)(e.g.,

total time when any of the units which

exhaust through the common stack are

operating).

HIu = Hourly average heat input rate for hour

h for the unit, mmBtu/hr.

tu = Unit operating time for hour h, in hours

or fraction of an hour (in equal

increments that can range from one

hundredth to one quarter of an hour, at

the option of the owner or operator). Use the hourly heat input rate at the

common stack level and the hourly average

NOX emission rate at the common stack level

and the procedures in section 8.1.1 of this

appendix to determine the hourly NOX mass

emissions at the common stack.

8.1.3 If a unit has multiple ducts and

NOX emission rate is only measured at one

duct, use the NOX emission rate measured at

the duct, the heat input measured for the

unit, and the procedures in section 8.1.1 of

this appendix to determine NOX mass

emissions.

8.1.4 If a unit has multiple ducts and

NOX emission rate is measured in each duct,

heat input shall also be measured in each

duct and the procedures in section 8.1.1 of

this appendix shall be used to determine

NOX mass emissions.

8.2 If a unit calculates NOX mass

emissions using a NOX concentration

monitoring system and a flow monitoring

system, calculate hourly NOX mass rate

during unit (or stack) operation, in lb/hr,

using Equation F–1 or F–2 in this appendix

(as applicable to the moisture basis of the

monitors). When using Equation F–1 or F–2,

replace ‘‘SO2’’ with ‘‘NOX’’ and replace the

value of K with 1.194 x 10¥7 (lb NOX /scf)/

ppm. (Include bias-adjusted flow rate or NOX

concentration values, where the bias-test

procedures in appendix A to this part shows

a bias-adjustment factor is necessary.)

8.3 If a unit calculates NOX mass

emissions using a NOX concentration

monitoring system and a flow monitoring

system, calculate NOX mass emissions for the

hour (lb) by multiplying the hourly NOX

mass emission rate during unit operation (lb/

hr) by the unit operating time during the

hour, as follows:

M E t Eq NO h h X h ( ) = ( . F-26)

Where:

M(NOx)h = NOX mass emissions in lbs for the

hour.

Eh = Hourly NOX mass emission rate during

unit (or stack) operation, lb/hr, from

section 8.2 of this appendix.

th = Monitoring location operating time for

hour h, in hours or fraction of an hour

(in equal increments that can range from

one hundredth to one quarter of an hour,

at the option of the owner or operator).

If the NOX mass emission rate is

monitored for all of the units in a

common stack, the monitoring location

operating time is equal to the total time

when any of those units was exhausting

through the common stack.

8.4 Use the following procedures to

calculate quarterly, cumulative ozone season,

and cumulative yearly NOX mass emissions,

in tons:

M

M

NO Eq F

NO

h

p

X

X

( )

( )

( . time period

h

= -27) =

∑

1

2000

Where:

M(NOx) time period = NOX mass emissions in tons

for the given time period (quarter,

cumulative ozone season, cumulative

year-to-date).

M(NOx)h = NOX mass emissions in lbs for the

hour. p = The number of hours in the

given time period (quarter, cumulative

ozone season, cumulative year-to-date).

8.5 Specific provisions for monitoring NOX

mass emissions from common stacks. The

owner or operator of a unit utilizing a

common stack may account for NOX mass

emissions using either of the following

methodologies, if the provisions of subpart H

are adopted as requirements of a State or

federal NOX mass reduction program:

8.5.1 The owner or operator may

determine both NOX emission rate and heat

input at the common stack and use the

procedures in section 8.1.1 of this appendix

to determine hourly NOX mass emissions at

the common stack.

8.5.2 The owner or operator may

determine the NOX emission rate at the

common stack and the heat input at each of

the units and use the procedures in section

8.1.2 of this appendix to determine the

hourly NOX mass emissions at each unit.

23. Part 96 is added to read as follows:

PART 96—NOX Budget Trading

Program for State Implementation

Plans

Subpart A—NOX Budget Trading

Program General Provisions

Sec.

96.1 Purpose.

96.2 Definitions.

96.3 Measurements, abbreviations, and

acronyms.

96.4 Applicability.

96.5 Retired unit exemption.

96.6 Standard requirements.

96.7 Computation of time.

Subpart B—Authorized Account

Representative for NOX Budget Sources

96.10 Authorization and responsibilities of

the NOX authorized account

representative.

96.11 Alternate NOX authorized account

representative.

96.12 Changing the NOX authorized

account representative and the alternate

NOX authorized account representative;

changes in the owners and operators.

96.13 Account certificate of representation.

96.14 Objections concerning the NOX

authorized account representative.

Subpart C—Permits

96.20 General NOX Budget permit

requirements.

96.21 Submission of NOX Budget permit

applications.

96.22 Information requirements for NOX

Budget permit applications.

96.23 NOX Budget permit contents.

96.24 Effective date of initial NOX Budget

permit.

96.25 NOX Budget permit revisions.

Subpart D—Compliance Certification

96.30 Compliance certification report.

96.31 Permitting authority’s and

Administrator’s action on compliance

certifications.

Subpart E—NOX Allowance Allocations

96.40 State trading program budget.

96.41 Timing requirements for NOX

allowance allocations.

96.42 NOX allowance allocations.

Subpart F—NOX Allowance Tracking

System

96.50 NOX Allowance Tracking System

accounts.

96.51 Establishment of accounts.

96.52 NOX Allowance Tracking System

responsibilities of NOX authorized

account representative.

96.53 Recordation of NOX allowance

allocations.

96.54 Compliance.

96.55 Banking.

96.56 Account error.

96.57 Closing of general accounts.
Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations 57515

Subpart G—NOX Allowance Transfers

96.60 Scope and submission of NOX

allowance transfers.

96.61 EPA recordation.

96.62 Notification.

Subpart H—Monitoring and Reporting

96.70 General requirements.

96.71 Initial certification and recertification

procedures.

96.72 Out of control periods.

96.73 Notifications.

96.74 Recordkeeping and reporting.

96.75 Petitions.

96.76 Additional requirements to provide

heat input data for allocations purposes.

Subpart I—Individual Unit Opt-ins

96.80 Applicability.

96.81 General.

96.82 NOX authorized account

representative.

96.83 Applying for NOX Budget opt-in

permit.

96.84 Opt-in process.

96.85 NOX Budget opt-in permit contents.

96.86 Withdrawal from NOX Budget

Trading Program.

96.87 Change in regulatory status.

96.88 NOX allowance allocations to opt-in

units.

Subpart J—Mobile and Area Sources

[Reserved]

Authority: 42 U.S.C. 7401, 7403, 7410, and

7601

Subpart A—NOX Budget Trading Program

General Provisions

§ 96.1 Purpose.

This part establishes general

provisions and the applicability,

permitting, allowance, excess emissions,

monitoring, and opt-in provisions for

the NOX Budget Trading Program for

State implementation plans as a means

of mitigating the interstate transport of

ozone and nitrogen oxides, an ozone

precursor. The owner or operator of a

unit, or any other person, shall comply

with requirements of this part as a

matter of federal law only to the extent

a State that has jurisdiction over the

unit incorporates by reference

provisions of this part, or otherwise

adopts such requirements of this part,

and requires compliance, the State

submits to the Administrator a State

implementation plan including such

adoption and such compliance

requirement, and the Administrator

approves the portion of the State

implementation plan including such

adoption and such compliance

requirement. To the extent a State

adopts requirements of this part,

including at a minimum the

requirements of subpart A (except for

§ 96.4(b)), subparts B through D, subpart

F (except for § 96.55(c)), and subparts G

and H of this part, the State authorizes

the Administrator to assist the State in

implementing the NOX Budget Trading

Program by carrying out the functions

set forth for the Administrator in such

requirements.

§ 96.2 Definitions.

The terms used in this part shall have

the meanings set forth in this section as

follows:

Account certificate of representation

means the completed and signed

submission required by subpart B of this

part for certifying the designation of a

NOX authorized account representative

for a NOX Budget source or a group of

identified NOX Budget sources who is

authorized to represent the owners and

operators of such source or sources and

of the NOX Budget units at such source

or sources with regard to matters under

the NOX Budget Trading Program.

Account number means the

identification number given by the

Administrator to each NOX Allowance

Tracking System account.

Acid Rain emissions limitation

means, as defined in § 72.2 of this

chapter, a limitation on emissions of

sulfur dioxide or nitrogen oxides under

the Acid Rain Program under title IV of

the CAA.

Administrator means the

Administrator of the United States

Environmental Protection Agency or the

Administrator’s duly authorized

representative.

Allocate or allocation means the

determination by the permitting

authority or the Administrator of the

number of NOX allowances to be

initially credited to a NOX Budget unit

or an allocation set-aside.

Automated data acquisition and

handling system or DAHS means that

component of the CEMS, or other

emissions monitoring system approved

for use under subpart H 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

H 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.

CAA means the CAA, 42 U.S.C. 7401,

et seq., as amended by Pub. L. No. 101–

549 (November 15, 1990).

Combined cycle system means a

system comprised of one or more

combustion turbines, heat recovery

steam generators, and steam turbines

configured to improve overall efficiency

of electricity generation or steam

production.

Combustion turbine means an

enclosed fossil or other fuel-fired device

that is comprised of 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.

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 § 96.5, for a unit that is a

NOX Budget unit under § 96.4 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, reconstructed,

or repowered. Except as provided in

§ 96.5 or subpart I of this part, for a unit

that is not a NOX Budget unit under

§ 96.4 on the date the unit commences

commercial operation, the date the unit

becomes a NOX Budget unit under

§ 96.4 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 § 96.5, for a unit that is a

NOX Budget unit under § 96.4 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,

reconstructed, or repowered. Except as

provided in § 96.5 or subpart I of this

part, for a unit that is not a NOX Budget

unit under § 96.4 on the date of

commencement of operation, the date

the unit becomes a NOX Budget unit

under § 96.4 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 NOX

Allowance Tracking System account,

established by the Administrator for a

NOX Budget unit under subpart F of this

part, in which the NOX allowance

allocations for the unit are initially

recorded and in which are held NOX

allowances available for use by the unit

for a control period for the purpose of

meeting the unit’s NOX Budget

emissions limitation.

Compliance certification means a

submission to the permitting authority
57516 Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations

or the Administrator, as appropriate,

that is required under subpart D of this

part to report a NOX Budget source’s or

a NOX Budget unit’s compliance or

noncompliance with this part and that

is signed by the NOX authorized account

representative in accordance with

subpart B of this part.

Continuous emission monitoring

system or CEMS means the equipment

required under subpart H of this part to

sample, analyze, measure, and provide,

by readings taken at least once every 15

minutes of the measured parameters, a

permanent record of nitrogen oxides

emissions, expressed in tons per hour

for nitrogen oxides. The following

systems are component parts included,

consistent with part 75 of this chapter,

in a continuous emission monitoring

system:

(1) Flow monitor;

(2) Nitrogen oxides pollutant

concentration monitors;

(3) Diluent gas monitor (oxygen or

carbon dioxide) when such monitoring

is required by subpart H of this part;

(4) A continuous moisture monitor

when such monitoring is required by

subpart H of this part; and

(5) An automated data acquisition and

handling system.

Control period means the period

beginning May 1 of a year and ending

on September 30 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

NOX authorized account representative

and as determined by the Administrator

in accordance with subpart H of this

part.

Energy Information Administration

means the Energy Information

Administration of the United States

Department of Energy.

Excess emissions means any tonnage

of nitrogen oxides emitted by a NOX

Budget unit during a control period that

exceeds the NOX Budget emissions

limitation for the unit.

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:

(1) The combustion of fossil fuel,

alone or in combination with any other

fuel, where fossil fuel actually

combusted comprises more than 50

percent of the annual heat input on a

Btu basis during any year starting in

1995 or, if a unit had no heat input

starting in 1995, during the last year of

operation of the unit prior to 1995; or

(2) The combustion of fossil fuel,

alone or in combination with any other

fuel, where fossil fuel is projected to

comprise more than 50 percent of the

annual heat input on a Btu basis during

any year; provided that the unit shall be

‘‘fossil fuel-fired’’ as of the date, during

such year, on which the unit begins

combusting fossil fuel.

General account means a NOX

Allowance Tracking System account,

established under subpart F of this part,

that is not a compliance account or an

overdraft account.

Generator means a device that

produces electricity.

Heat input means the product (in

mmBtu/time) of the gross calorific value

of the fuel (in Btu/lb) and the fuel feed

rate into a combustion device (in mass

of fuel/time), as measured, recorded,

and reported to the Administrator by the

NOX authorized account representative

and as determined by the Administrator

in accordance with subpart H of this

part, and does not include the heat

derived from preheated combustion air,

recirculated flue gases, or exhaust from

other sources.

Life-of-the-unit, firm power

contractual arrangement means a unit

participation power sales agreement

under which a utility or industrial

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 equal to or greater

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 ability of a unit to combust a stated

maximum amount of fuel per hour on a

steady state basis, as determined by the

physical design and physical

characteristics of the unit.

Maximum potential hourly heat input

means an hourly heat input used for

reporting purposes when a unit lacks

certified monitors to report heat input.

If the unit intends to use appendix D of

part 75 of this chapter to report heat

input, this value should be calculated,

in accordance with part 75 of this

chapter, using the maximum fuel flow

rate and the maximum gross calorific

value. If the unit intends to use a flow

monitor and a diluent gas monitor, this

value should be reported, in accordance

with part 75 of this chapter, using the

maximum potential flowrate and either

the maximum carbon dioxide

concentration (in percent CO2) or the

minimum oxygen concentration (in

percent O2).

Maximum potential NOX emission

rate means the emission rate of nitrogen

oxides (in lb/mmBtu) calculated in

accordance with section 3 of appendix

F of part 75 of this chapter, using the

maximum potential nitrogen oxides

concentration as defined in section 2 of

appendix A of part 75 of this chapter,

and either the maximum oxygen

concentration (in percent O2) or the

minimum carbon dioxide concentration

(in percent CO2), under all operating

conditions of the unit except for unit

start up, shutdown, and upsets.

Maximum rated hourly heat input

means a unit-specific maximum hourly

heat input (mmBtu) which is the higher

of the manufacturer’s maximum rated

hourly heat input or the highest

observed hourly heat input.

Monitoring system means any

monitoring system that meets the

requirements of subpart H of this part,

including a continuous emissions

monitoring system, an excepted

monitoring system, or an alternative

monitoring system.

Most stringent State or Federal NOX

emissions limitation means, with regard

to a NOX Budget opt-in source, the

lowest NOX emissions limitation (in

terms of lb/mmBtu) that is applicable to

the unit under State or Federal law,

regardless of the averaging period to

which the emissions limitation applies.

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 measured in accordance with the

United States Department of Energy

standards.

Non-title V permit means a federally

enforceable permit administered by the

permitting authority pursuant to the

CAA and regulatory authority under the

CAA, other than title V of the CAA and

part 70 or 71 of this chapter.

NOX allowance means an

authorization by the permitting

authority or the Administrator under the

NOX Budget Trading Program to emit up

to one ton of nitrogen oxides during the

control period of the specified year or of

any year thereafter.

NOX allowance deduction or deduct

NOX allowances means the permanent

withdrawal of NOX allowances by the
Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations 57517

Administrator from a NOX Allowance

Tracking System compliance account or

overdraft account to account for the

number of tons of NOX emissions from

a NOX Budget unit for a control period,

determined in accordance with subpart

H of this part, or for any other allowance

surrender obligation under this part.

NOX allowances held or hold NOX

allowances means the NOX allowances

recorded by the Administrator, or

submitted to the Administrator for

recordation, in accordance with

subparts F and G of this part, in a NOX

Allowance Tracking System account.

NOX Allowance Tracking System

means the system by which the

Administrator records allocations,

deductions, and transfers of NOX

allowances under the NOX Budget

Trading Program.

NOX Allowance Tracking System

account means an account in the NOX

Allowance Tracking System established

by the Administrator for purposes of

recording the allocation, holding,

transferring, or deducting of NOX

allowances.

NOX allowance transfer deadline

means midnight of November 30 or, if

November 30 is not a business day,

midnight of the first business day

thereafter and is the deadline by which

NOX allowances may be submitted for

recordation in a NOX Budget unit’s

compliance account, or the overdraft

account of the source where the unit is

located, in order to meet the unit’s NOX

Budget emissions limitation for the

control period immediately preceding

such deadline.

NOX authorized account

representative means, for a NOX Budget

source or NOX Budget unit at the source,

the natural person who is authorized by

the owners and operators of the source

and all NOX Budget units at the source,

in accordance with subpart B of this

part, to represent and legally bind each

owner and operator in matters

pertaining to the NOX Budget Trading

Program or, for a general account, the

natural person who is authorized, in

accordance with subpart F of this part,

to transfer or otherwise dispose of NOX

allowances held in the general account.

NOX Budget emissions limitation

means, for a NOX Budget unit, the

tonnage equivalent of the NOX

allowances available for compliance

deduction for the unit and for a control

period under § 96.54(a) and (b), adjusted

by any deductions of such NOX

allowances to account for actual

utilization under § 96.42(e) for the

control period or to account for excess

emissions for a prior control period

under § 96.54(d) or to account for

withdrawal from the NOX Budget

Program, or for a change in regulatory

status, for a NOX Budget opt-in source

under § 96.86 or § 96.87.

NOX Budget opt-in permit means a

NOX Budget permit covering a NOX

Budget opt-in source.

NOX Budget opt-in source means a

unit that has been elected to become a

NOX Budget unit under the NOX Budget

Trading Program and whose NOX

Budget opt-in permit has been issued

and is in effect under subpart I of this

part.

NOX Budget permit means the legally

binding and federally enforceable

written document, or portion of such

document, issued by the permitting

authority under this part, including any

permit revisions, specifying the NOX

Budget Trading Program requirements

applicable to a NOX Budget source, to

each NOX Budget unit at the NOX

Budget source, and to the owners and

operators and the NOX authorized

account representative of the NOX

Budget source and each NOX Budget

unit.

NOX Budget source means a source

that includes one or more NOX Budget

units.

NOX Budget Trading Program means

a multi-state nitrogen oxides air

pollution control and emission

reduction program established in

accordance with this part and pursuant

to § 51.121 of this chapter, as a means

of mitigating the interstate transport of

ozone and nitrogen oxides, an ozone

precursor.

NOX Budget unit means a unit that is

subject to the NOX Budget Trading

Program emissions limitation under

§ 96.4 or § 96.80.

Operating means, with regard to a

unit under §§ 96.22(d)(2) and 96.80,

having documented heat input for more

than 876 hours in the 6 months

immediately preceding the submission

of an application for an initial NOX

Budget permit under § 96.83(a).

Operator means any person who

operates, controls, or supervises a NOX

Budget unit, a NOX Budget source, or

unit for which an application for a NOX

Budget opt-in permit under § 96.83 is

submitted and not denied or withdrawn

and shall include, but not be limited to,

any holding company, utility system, or

plant manager of such a unit or source.

Opt-in means to be elected to become

a NOX Budget unit under the NOX

Budget Trading Program through a final,

effective NOX Budget opt-in permit

under subpart I of this part.

Overdraft account means the NOX

Allowance Tracking System account,

established by the Administrator under

subpart F of this part, for each NOX

Budget source where there are two or

more NOX Budget units.

Owner means any of the following

persons:

(1) Any holder of any portion of the

legal or equitable title in a NOX Budget

unit or in a unit for which an

application for a NOX Budget opt-in

permit under § 96.83 is submitted and

not denied or withdrawn; or

(2) Any holder of a leasehold interest

in a NOX Budget unit or in a unit for

which an application for a NOX Budget

opt-in permit under § 96.83 is submitted

and not denied or withdrawn; or

(3) Any purchaser of power from a

NOX Budget unit or from a unit for

which an application for a NOX Budget

opt-in permit under § 96.83 is submitted

and not denied or withdrawn under a

life-of-the-unit, firm power contractual

arrangement. However, 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, upon the revenues

or income from the NOX Budget unit or

the unit for which an application for a

NOX Budget opt-in permit under § 96.83

is submitted and not denied or

withdrawn; or

(4) With respect to any general

account, any person who has an

ownership interest with respect to the

NOX allowances held in the general

account and who is subject to the

binding agreement for the NOX

authorized account representative to

represent that person’s ownership

interest with respect to 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 NOX Budget

Trading Program in accordance with

subpart C of this part.

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

writing 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 NOX allowances,

the movement of NOX allowances by the

Administrator from one NOX Allowance

Tracking System account to another, for

purposes of allocation, transfer, or

deduction.
57518 Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations

Reference method means any direct

test method of sampling and analyzing

for an air pollutant as specified in

appendix A of part 60 of this chapter.

Serial number means, when referring

to NOX allowances, the unique

identification number assigned to each

NOX allowance by the Administrator,

under § 96.53(c).

Source means any governmental,

institutional, commercial, or industrial

structure, installation, plant, building,

or facility that emits or has the potential

to emit any regulated air pollutant

under the CAA. For purposes of section

502(c) of the CAA, a ‘‘source,’’ including

a ‘‘source’’ with multiple units, shall be

considered a single ‘‘facility.’’

State means one of the 48 contiguous

States and the District of Columbia

specified in § 51.121 of this chapter, or

any non-federal authority in or

including such States or the District of

Columbia (including local agencies, and

Statewide agencies) or any eligible

Indian tribe in an area of such State or

the District of Columbia, that adopts a

NOX Budget Trading Program pursuant

to § 51.121 of this chapter. To the extent

a State incorporates by reference the

provisions of this part, the term ‘‘State’’

shall mean the incorporating State. The

term ‘‘State’’ shall have its conventional

meaning where such meaning is clear

from the context.

State trading program budget means

the total number of NOX tons

apportioned to all NOX Budget units in

a given State, in accordance with the

NOX Budget Trading Program, for use in

a given control period.

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 CAA

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 CAA and part 70 or 71 of this

chapter.

Ton or tonnage means any ‘‘short ton’’

(i.e., 2,000 pounds). For the purpose of

determining compliance with the NOX

Budget emissions limitation, total tons

for a control period shall be calculated

as the sum of all recorded hourly

emissions (or the tonnage equivalent of

the recorded hourly emissions rates) in

accordance with subpart H of this part,

with any remaining fraction of a ton

equal to or greater than 0.50 ton deemed

to equal one ton and any fraction of a

ton less than 0.50 ton deemed to equal

zero tons.

Unit means a fossil fuel-fired

stationary boiler, combustion turbine, or

combined cycle system.

Unit load means the total (i.e., gross)

output of a unit in any control period

(or other specified time period)

produced by combusting a given heat

input of fuel, expressed in terms of:

(1) The total electrical generation

(MWe) produced by the unit, including

generation for use within the plant; or

(2) In the case of a unit that uses heat

input for purposes other than electrical

generation, the total steam pressure

(psia) produced by the unit, including

steam for use by the unit.

Unit operating day means a calendar

day in which a unit combusts any fuel.

Unit operating hour or hour of unit

operation means any hour (or fraction of

an hour) during which a unit combusts

any fuel.

Utilization means the heat input

(expressed in mmBtu/time) for a unit.

The unit’s total heat input for the

control period in each year will be

determined in accordance with part 75

of this chapter if the NOX Budget 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

Administrator for the unit if the unit

was not otherwise subject to the

requirements of part 75 of this chapter

for the year.

§ 96.3 Measurements, abbreviations, and

acronyms.

Measurements, abbreviations, and

acronyms used in this part are defined

as follows:

Btu—British thermal unit.

hr—hour.

Kwh—kilowatt hour.

lb—pounds.

mmBtu—million Btu.

MWe—megawatt electrical.

ton—2000 pounds.

CO2—carbon dioxide.

NOX—nitrogen oxides.

O2—oxygen.

§ 96.4 Applicability.

(a) The following units in a State shall

be NOX Budget units, and any source

that includes one or more such units

shall be a NOX Budget source, subject to

the requirements of this part:

(1) Any unit that, any time on or after

January 1, 1995, serves a generator with

a nameplate capacity greater than 25

MWe and sells any amount of

electricity; or

(2) Any unit that is not a unit under

paragraph (a) of this section and that has

a maximum design heat input greater

than 250 mmBtu/hr.

(b) Notwithstanding paragraph (a) of

this section, a unit under paragraph (a)

of this section shall be subject only to

the requirements of this paragraph (b) if

the unit has a federally enforceable

permit that meets the requirements of

paragraph (b)(1) of this section and

restricts the unit to burning only natural

gas or fuel oil during a control period

in 2003 or later and each control period

thereafter and restricts the unit’s

operating hours during each such

control period to the number of hours

(determined in accordance with

paragraph (b)(1)(ii) and (iii) of this

section) that limits the unit’s potential

NOX mass emissions for the control

period to 25 tons or less.

Notwithstanding paragraph (a) of this

section, starting with the effective date

of such federally enforceable permit, the

unit shall not be a NOX Budget unit.

(1) For each control period under

paragraph (b) of this section, the

federally enforceable permit must:

(i) Restrict the unit to burning only

natural gas or fuel oil.

(ii) Restrict the unit’s operating hours

to the number calculated by dividing 25

tons of potential NOX mass emissions by

the unit’s maximum potential hourly

NOX mass emissions.

(iii) Require that the unit’s potential

NOX mass emissions shall be calculated

as follows:

(A) Select the default NOX emission

rate in Table 2 of § 75.19 of this chapter

that would otherwise be applicable

assuming that the unit burns only the

type of fuel (i.e., only natural gas or only

fuel oil) that has the highest default

NOX emission factor of any type of fuel

that the unit is allowed to burn under

the fuel use restriction in paragraph

(b)(1)(i) of this section; and

(B) Multiply the default NOX emission

rate under paragraph (b)(1)(iii)(A) of this

section by the unit’s maximum rated

hourly heat input. The owner or

operator of the unit may petition the

permitting authority to use a lower

value for the unit’s maximum rated

hourly heat input than the value as

defined under § 96.2. The permitting

authority may approve such lower value

if the owner or operator demonstrates

that the maximum hourly heat input

specified by the manufacturer or the

highest observed hourly heat input, or

both, are not representative, and that

such lower value is representative, of

the unit’s current capabilities because
Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations 57519

modifications have been made to the

unit, limiting its capacity permanently.

(iv) Require that the owner or operator

of the unit shall retain at the source that

includes the unit, for 5 years, records

demonstrating that the operating hours

restriction, the fuel use restriction, and

the other requirements of the permit

related to these restrictions were met.

(v) Require that the owner or operator

of the unit shall report the unit’s hours

of operation (treating any partial hour of

operation as a whole hour of operation)

during each control period to the

permitting authority by November 1 of

each year for which the unit is subject

to the federally enforceable permit.

(2) The permitting authority that

issues the federally enforceable permit

with the fuel use restriction under

paragraph (b)(1)(i) and the operating

hours restriction under paragraphs

(b)(1)(ii) and (iii) of this section will

notify the Administrator in writing of

each unit under paragraph (a) of this

section whose federally enforceable

permit issued by the permitting

authority includes such restrictions. The

permitting authority will also notify the

Administrator in writing of each unit

under paragraph (a) of this section

whose federally enforceable permit

issued by the permitting authority is

revised to remove any such restriction,

whose federally enforceable permit

issued by the permitting authority

includes any such restriction that is no

longer applicable, or which does not

comply with any such restriction.

(3) If, for any control period under

paragraph (b) of this section, the fuel

use restriction under paragraph (b)(1)(i)

of this section or the operating hours

restriction under paragraphs (b)(1)(ii)

and (iii) of this section is removed from

the unit’s federally enforceable permit

or otherwise becomes no longer

applicable or if, for any such control

period, the unit does not comply with

the fuel use restriction under paragraph

(b)(1)(i) of this section or the operating

hours restriction under paragraphs

(b)(1)(ii) and (iii) of this section, the unit

shall be a NOX Budget unit, subject to

the requirements of this part. Such unit

shall be treated as commencing

operation and, for a unit under

paragraph (a)(1) of this section,

commencing commercial operation on

September 30 of the control period for

which the fuel use restriction or the

operating hours restriction is no longer

applicable or during which the unit

does not comply with the fuel use

restriction or the operating hours

restriction.

§ 96.5 Retired unit exemption.

(a) This section applies to any NOX

Budget unit, other than a NOX Budget

opt-in source, that is permanently

retired.

(b)(1) Any NOX Budget unit, other

than a NOX Budget opt-in source, that

is permanently retired shall be exempt

from the NOX Budget Trading Program,

except for the provisions of this section,

§§ 96.2, 96.3, 96.4, 96.7 and subparts E,

F, and G 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 NOX

authorized account representative

(authorized in accordance with subpart

B of this part) shall submit a statement

to the permitting authority otherwise

responsible for administering any NOX

Budget permit for the unit. A copy of

the statement shall be submitted to the

Administrator. The statement shall state

(in a format prescribed by the permitting

authority) that the unit is permanently

retired 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 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. The

owners and operators of the unit will be

allocated allowances in accordance with

subpart E of this part.

(2)(i) 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 NOX authorized account

representative of the source submits a

complete NOX Budget permit

application under § 96.22 for the unit

not less than 18 months (or such lesser

time provided under the permitting

authority’s title V operating permits

regulations for final action on a permit

application) prior to the later of May 1,

2003 or the date on which the unit is to

first resume operation.

(ii) 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 non-title V permit

shall not resume operation unless the

NOX authorized account representative

of the source submits a complete NOX

Budget permit application under § 96.22

for the unit not less than 18 months (or

such lesser time provided under the

permitting authority’s non-title V

permits regulations for final action on a

permit application) prior to the later of

May 1, 2003 or the date on which the

unit is to first resume operation.

(3) The owners and operators and, to

the extent applicable, the NOX

authorized account representative of a

unit exempt under this section shall

comply with the requirements of the

NOX Budget 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 that is exempt under this

section is not eligible to be a NOX

Budget opt-in source under subpart I of

this part.

(5) 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.

(6) Loss of exemption. (i) On the

earlier of the following dates, a unit

exempt under paragraph (b) of this

section shall lose its exemption:

(A) The date on which the NOX

authorized account representative

submits a NOX Budget permit

application under paragraph (c)(2) of

this section; or

(B) The date on which the NOX

authorized account representative is

required under paragraph (c)(2) of this

section to submit a NOX Budget permit

application.

(ii) For the purpose of applying

monitoring requirements under subpart

H of this part, a unit that loses its

exemption under this section shall be

treated as a unit that commences

operation or commercial operation on

the first date on which the unit resumes

operation.

§ 96.6 Standard requirements.

(a) Permit Requirements. (1) The NOX

authorized account representative of

each NOX Budget source required to

have a federally enforceable permit and

each NOX Budget unit required to have

a federally enforceable permit at the

source shall:

(i) Submit to the permitting authority

a complete NOX Budget permit

application under § 96.22 in accordance
57520 Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations

with the deadlines specified in

§ 96.21(b) and (c);

(ii) Submit in a timely manner any

supplemental information that the

permitting authority determines is

necessary in order to review a NOX

Budget permit application and issue or

deny a NOX Budget permit.

(2) The owners and operators of each

NOX Budget source required to have a

federally enforceable permit and each

NOX Budget unit required to have a

federally enforceable permit at the

source shall have a NOX Budget permit

issued by the permitting authority and

operate the unit in compliance with

such NOX Budget permit.

(3) The owners and operators of a

NOX Budget source that is not otherwise

required to have a federally enforceable

permit are not required to submit a NOX

Budget permit application, and to have

a NOX Budget permit, under subpart C

of this part for such NOX Budget source.

(b) Monitoring requirements. (1) The

owners and operators and, to the extent

applicable, the NOX authorized account

representative of each NOX Budget

source and each NOX Budget unit at the

source shall comply with the

monitoring requirements of subpart H of

this part.

(2) The emissions measurements

recorded and reported in accordance

with subpart H of this part shall be used

to determine compliance by the unit

with the NOX Budget emissions

limitation under paragraph (c) of this

section.

(c) Nitrogen oxides requirements. (1)

The owners and operators of each NOX

Budget source and each NOX Budget

unit at the source shall hold NOX

allowances available for compliance

deductions under § 96.54, as of the NOX

allowance transfer deadline, in the

unit’s compliance account and the

source’s overdraft account in an amount

not less than the total NOX emissions for

the control period from the unit, as

determined in accordance with subpart

H of this part, plus any amount

necessary to account for actual

utilization under § 96.42(e) for the

control period.

(2) Each ton of nitrogen oxides

emitted in excess of the NOX Budget

emissions limitation shall constitute a

separate violation of this part, the CAA,

and applicable State law.

(3) A NOX Budget unit shall be subject

to the requirements under paragraph

(c)(1) of this section starting on the later

of May 1, 2003 or the date on which the

unit commences operation.

(4) NOX allowances shall be held in,

deducted from, or transferred among

NOX Allowance Tracking System

accounts in accordance with subparts E,

F, G, and I of this part.

(5) A 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 NOX

allowance was allocated.

(6) A NOX allowance allocated by the

permitting authority or the

Administrator under the NOX Budget

Trading Program is a limited

authorization to emit one ton of nitrogen

oxides in accordance with the NOX

Budget Trading Program. No provision

of the NOX Budget Trading Program, the

NOX Budget permit application, the

NOX Budget permit, or an exemption

under § 96.5 and no provision of law

shall be construed to limit the authority

of the United States or the State to

terminate or limit such authorization.

(7) A NOX allowance allocated by the

permitting authority or the

Administrator under the NOX Budget

Trading Program does not constitute a

property right.

(8) Upon recordation by the

Administrator under subpart F, G, or I

of this part, every allocation, transfer, or

deduction of a NOX allowance to or

from a NOX Budget unit’s compliance

account or the overdraft account of the

source where the unit is located is

deemed to amend automatically, and

become a part of, any NOX Budget

permit of the NOX Budget unit by

operation of law without any further

review.

(d) Excess emissions requirements. (1)

The owners and operators of a NOX

Budget unit that has excess emissions in

any control period shall:

(i) Surrender the NOX allowances

required for deduction under

§ 96.54(d)(1); and

(ii) Pay any fine, penalty, or

assessment or comply with any other

remedy imposed under § 96.54(d)(3).

(e) Recordkeeping and Reporting

requirements.

(1) Unless otherwise provided, the

owners and operators of the NOX Budget

source and each NOX Budget 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 account certificate of

representation for the NOX authorized

account representative for the source

and each NOX Budget unit at the source

and all documents that demonstrate the

truth of the statements in the account

certificate of representation, in

accordance with § 96.13; 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 account

certificate of representation changing

the NOX authorized account

representative.

(ii) All emissions monitoring

information, in accordance with subpart

H of this part; provided that to the

extent that subpart H 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 NOX Budget Trading Program.

(iv) Copies of all documents used to

complete a NOX Budget permit

application and any other submission

under the NOX Budget Trading Program

or to demonstrate compliance with the

requirements of the NOX Budget

Trading Program.

(2) The NOX authorized account

representative of a NOX Budget source

and each NOX Budget unit at the source

shall submit the reports and compliance

certifications required under the NOX

Budget Trading Program, including

those under subparts D, H, or I of this

part.

(f) Liability. (1) Any person who

knowingly violates any requirement or

prohibition of the NOX Budget Trading

Program, a NOX Budget permit, or an

exemption under § 96.5 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 NOX

Budget 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

NOX Budget Trading Program that

occurs prior to the date that the revision

takes effect.

(4) Each NOX Budget source and each

NOX Budget unit shall meet the

requirements of the NOX Budget

Trading Program.

(5) Any provision of the NOX Budget

Trading Program that applies to a NOX

Budget source (including a provision

applicable to the NOX authorized

account representative of a NOX Budget

source) shall also apply to the owners

and operators of such source and of the

NOX Budget units at the source.

(6) Any provision of the NOX Budget

Trading Program that applies to a NOX

Budget unit (including a provision

applicable to the NOX authorized
Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations 57521

account representative of a NOX budget

unit) shall also apply to the owners and

operators of such unit. Except with

regard to the requirements applicable to

units with a common stack under

subpart H of this part, the owners and

operators and the NOX authorized

account representative of one NOX

Budget unit shall not be liable for any

violation by any other NOX Budget unit

of which they are not owners or

operators or the NOX authorized

account representative and that is

located at a source of which they are not

owners or operators or the NOX

authorized account representative.

(g) Effect on other authorities. No

provision of the NOX Budget Trading

Program, a NOX Budget permit

application, a NOX Budget permit, or an

exemption under § 96.5 shall be

construed as exempting or excluding the

owners and operators and, to the extent

applicable, the NOX authorized account

representative of a NOX Budget source

or NOX Budget unit from compliance

with any other provision of the

applicable, approved State

implementation plan, a federally

enforceable permit, or the CAA.

§ 96.7 Computation of time.

(a) Unless otherwise stated, any time

period scheduled, under the NOX

Budget 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 NOX

Budget 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 NOX

Budget Trading Program, falls on a

weekend or a State or Federal holiday,

the time period shall be extended to the

next business day.

Subpart B—NOX Authorized Account

Representative for NOX Budget

Sources

§ 96.10 Authorization and responsibilities

of the NOX authorized account

representative.

(a) Except as provided under § 96.11,

each NOX Budget source, including all

NOX Budget units at the source, shall

have one and only one NOX authorized

account representative, with regard to

all matters under the NOX Budget

Trading Program concerning the source

or any NOX Budget unit at the source.

(b) The NOX authorized account

representative of the NOX Budget source

shall be selected by an agreement

binding on the owners and operators of

the source and all NOX Budget units at

the source.

(c) Upon receipt by the Administrator

of a complete account certificate of

representation under § 96.13, the NOX

authorized account representative of the

source shall represent and, by his or her

representations, actions, inactions, or

submissions, legally bind each owner

and operator of the NOX Budget source

represented and each NOX Budget unit

at the source in all matters pertaining to

the NOX Budget Trading Program, not

withstanding any agreement between

the NOX authorized account

representative and such owners and

operators. The owners and operators

shall be bound by any decision or order

issued to the NOX authorized account

representative by the permitting

authority, the Administrator, or a court

regarding the source or unit.

(d) No NOX Budget permit shall be

issued, and no NOX Allowance Tracking

System account shall be established for

a NOX Budget unit at a source, until the

Administrator has received a complete

account certificate of representation

under § 96.13 for a NOX authorized

account representative of the source and

the NOX Budget units at the source.

(e)(1) Each submission under the NOX

Budget Trading Program shall be

submitted, signed, and certified by the

NOX authorized account representative

for each NOX Budget source on behalf

of which the submission is made. Each

such submission shall include the

following certification statement by the

NOX authorized account representative:

‘‘I am authorized to make this

submission on behalf of the owners and

operators of the NOX Budget sources or

NOX Budget 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 NOX Budget source or a

NOX Budget unit only if the submission

has been made, signed, and certified in

accordance with paragraph (e)(1) of this

section.

§ 96.11 Alternate NOX authorized account

representative.

(a) An account certificate of

representation may designate one and

only one alternate NOX authorized

account representative who may act on

behalf of the NOX authorized account

representative. The agreement by which

the alternate NOX authorized account

representative is selected shall include

a procedure for authorizing the alternate

NOX authorized account representative

to act in lieu of the NOX authorized

account representative.

(b) Upon receipt by the Administrator

of a complete account certificate of

representation under § 96.13, any

representation, action, inaction, or

submission by the alternate NOX

authorized account representative shall

be deemed to be a representation,

action, inaction, or submission by the

NOX authorized account representative.

(c) Except in this section and

§§ 96.10(a), 96.12, 96.13, and 96.51,

whenever the term ‘‘NOX authorized

account representative’’ is used in this

part, the term shall be construed to

include the alternate NOX authorized

account representative.

§ 96.12 Changing the NOX authorized

account representative and the alternate

NOX authorized account representative;

changes in the owners and operators.

(a) Changing the NOX authorized

account representative. The NOX

authorized account representative may

be changed at any time upon receipt by

the Administrator of a superseding

complete account certificate of

representation under § 96.13.

Notwithstanding any such change, all

representations, actions, inactions, and

submissions by the previous NOX

authorized account representative prior

to the time and date when the

Administrator receives the superseding

account certificate of representation

shall be binding on the new NOX

authorized account representative and

the owners and operators of the NOX

Budget source and the NOX Budget

units at the source.

(b) Changing the alternate NOX

authorized account representative. The

alternate NOX authorized account

representative may be changed at any

time upon receipt by the Administrator

of a superseding complete account

certificate of representation under

§ 96.13. Notwithstanding any such

change, all representations, actions,

inactions, and submissions by the

previous alternate NOX authorized

account representative prior to the time

and date when the Administrator

receives the superseding account

certificate of representation shall be
57522 Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations

binding on the new alternate NOX

authorized account representative and

the owners and operators of the NOX

Budget source and the NOX Budget

units at the source.

(c) Changes in the owners and

operators. (1) In the event a new owner

or operator of a NOX Budget source or

a NOX Budget unit is not included in

the list of owners and operators

submitted in the account certificate of

representation, such new owner or

operator shall be deemed to be subject

to and bound by the account certificate

of representation, the representations,

actions, inactions, and submissions of

the NOX authorized account

representative and any alternate NOX

authorized account 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 NOX Budget source or a NOX Budget

unit, including the addition of a new

owner or operator, the NOX authorized

account representative or alternate NOX

authorized account representative shall

submit a revision to the account

certificate of representation amending

the list of owners and operators to

include the change.

§ 96.13 Account certificate of

representation.

(a) A complete account certificate of

representation for a NOX authorized

account representative or an alternate

NOX authorized account representative

shall include the following elements in

a format prescribed by the

Administrator:

(1) Identification of the NOX Budget

source and each NOX Budget unit at the

source for which the account certificate

of representation is submitted.

(2) The name, address, e-mail address

(if any), telephone number, and

facsimile transmission number (if any)

of the NOX authorized account

representative and any alternate NOX

authorized account representative.

(3) A list of the owners and operators

of the NOX Budget source and of each

NOX Budget unit at the source.

(4) The following certification

statement by the NOX authorized

account representative and any alternate

NOX authorized account representative:

‘‘I certify that I was selected as the NOX

authorized account representative or

alternate NOX authorized account

representative, as applicable, by an

agreement binding on the owners and

operators of the NOX Budget source and

each NOX Budget unit at the source. I

certify that I have all the necessary

authority to carry out my duties and

responsibilities under the NOX Budget

Trading Program on behalf of the

owners and operators of the NOX Budget

source and of each NOX Budget unit at

the source and that each such owner

and operator shall be fully bound by my

representations, actions, inactions, or

submissions and by any decision or

order issued to me by the permitting

authority, the Administrator, or a court

regarding the source or unit.’’

(5) The signature of the NOX

authorized account representative and

any alternate NOX authorized account

representative and the dates signed.

(b) Unless otherwise required by the

permitting authority or the

Administrator, documents of agreement

referred to in the account 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.

§ 96.14 Objections concerning the NOX

authorized account representative.

(a) Once a complete account

certificate of representation under

§ 96.13 has been submitted and

received, the permitting authority and

the Administrator will rely on the

account certificate of representation

unless and until a superseding complete

account certificate of representation

under § 96.13 is received by the

Administrator.

(b) Except as provided in § 96.12(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

NOX authorized account representative

shall affect any representation, action,

inaction, or submission of the NOX

authorized account representative or the

finality of any decision or order by the

permitting authority or the

Administrator under the NOX Budget

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

NOX authorized account representative,

including private legal disputes

concerning the proceeds of NOX

allowance transfers.

Subpart C—Permits

§ 96.20 General NOX Budget trading

program permit requirements.

(a) For each NOX Budget source

required to have a federally enforceable

permit, such permit shall include a NOX

Budget permit administered by the

permitting authority.

(1) For NOX Budget sources required

to have a title V operating permit, the

NOX Budget 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 or subpart I of this part.

The applicable provisions of such title

V operating permits regulations shall

include, but are not limited to, those

provisions addressing operating permit

applications, operating permit

application shield, operating permit

duration, operating permit shield,

operating permit issuance, operating

permit revision and reopening, public

participation, State review, and review

by the Administrator.

(2) For NOX Budget sources required

to have a non-title V permit, the NOX

Budget portion of the non-title V permit

shall be administered in accordance

with the permitting authority’s

regulations promulgated to administer

non-title V permits, except as provided

otherwise by this subpart or subpart I of

this part. The applicable provisions of

such non-title V permits regulations

may include, but are not limited to,

provisions addressing permit

applications, permit application shield,

permit duration, permit shield, permit

issuance, permit revision and

reopening, public participation, State

review, and review by the

Administrator.

(b) Each NOX Budget permit

(including a draft or proposed NOX

Budget permit, if applicable) shall

contain all applicable NOX Budget

Trading Program requirements and shall

be a complete and segregable portion of

the permit under paragraph (a) of this

section.

§ 96.21 Submission of NOX Budget permit

applications.

(a) Duty to apply. The NOX authorized

account representative of any NOX

Budget source required to have a

federally enforceable permit shall

submit to the permitting authority a

complete NOX Budget permit

application under § 96.22 by the

applicable deadline in paragraph (b) of

this section.
Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations 57523

(b)(1) For NOX Budget sources

required to have a title V operating

permit:

(i) For any source, with one or more

NOX Budget units under § 96.4 that

commence operation before January 1,

2000, the NOX authorized account

representative shall submit a complete

NOX Budget permit application under

§ 96.22 covering such NOX Budget units

to the permitting authority at least 18

months (or such lesser time provided

under the permitting authority’s title V

operating permits regulations for final

action on a permit application) before

May 1, 2003.

(ii) For any source, with any NOX

Budget unit under § 96.4 that

commences operation on or after

January 1, 2000, the NOX authorized

account representative shall submit a

complete NOX Budget permit

application under § 96.22 covering such

NOX Budget unit to the permitting

authority at least 18 months (or such

lesser time provided under the

permitting authority’s title V operating

permits regulations for final action on a

permit application) before the later of

May 1, 2003 or the date on which the

NOX Budget unit commences operation.

(2) For NOX Budget sources required

to have a non-title V permit:

(i) For any source, with one or more

NOX Budget units under § 96.4 that

commence operation before January 1,

2000, the NOX authorized account

representative shall submit a complete

NOX Budget permit application under

§ 96.22 covering such NOX Budget units

to the permitting authority at least 18

months (or such lesser time provided

under the permitting authority’s nontitle V permits regulations for final

action on a permit application) before

May 1, 2003.

(ii) For any source, with any NOX

Budget unit under § 96.4 that

commences operation on or after

January 1, 2000, the NOX authorized

account representative shall submit a

complete NOX Budget permit

application under § 96.22 covering such

NOX Budget unit to the permitting

authority at least 18 months (or such

lesser time provided under the

permitting authority’s non-title V

permits regulations for final action on a

permit application) before the later of

May 1, 2003 or the date on which the

NOX Budget unit commences operation.

(c) Duty to reapply. (1) For a NOX

Budget source required to have a title V

operating permit, the NOX authorized

account representative shall submit a

complete NOX Budget permit

application under § 96.22 for the NOX

Budget source covering the NOX Budget

units at the source in accordance with

the permitting authority’s title V

operating permits regulations

addressing operating permit renewal.

(2) For a NOX Budget source required

to have a non-title V permit, the NOX

authorized account representative shall

submit a complete NOX Budget permit

application under § 96.22 for the NOX

Budget source covering the NOX Budget

units at the source in accordance with

the permitting authority’s non-title V

permits regulations addressing permit

renewal.

§ 96.22 Information requirements for NOX

Budget permit applications.

A complete NOX Budget permit

application shall include the following

elements concerning the NOX Budget

source for which the application is

submitted, in a format prescribed by the

permitting authority:

(a) Identification of the NOX Budget

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 NOX Budget

unit at the NOX Budget source and

whether it is a NOX Budget unit under

§ 96.4 or under subpart I of this part;

(c) The standard requirements under

§ 96.6; and

(d) For each NOX Budget opt-in unit

at the NOX Budget source, the following

certification statements by the NOX

authorized account representative:

(1) ‘‘I certify that each unit for which

this permit application is submitted

under subpart I of this part is not a NOX

Budget unit under 40 CFR 96.4 and is

not covered by a retired unit exemption

under 40 CFR 96.5 that is in effect.’’

(2) If the application is for an initial

NOX Budget opt-in permit, ‘‘I certify

that each unit for which this permit

application is submitted under subpart

I is currently operating, as that term is

defined under 40 CFR 96.2.’’

§ 96.23 NOX Budget permit contents.

(a) Each NOX Budget permit

(including any draft or proposed NOX

Budget permit, if applicable) will

contain, in a format prescribed by the

permitting authority, all elements

required for a complete NOX Budget

permit application under § 96.22 as

approved or adjusted by the permitting

authority.

(b) Each NOX Budget permit is

deemed to incorporate automatically the

definitions of terms under § 96.2 and,

upon recordation by the Administrator

under subparts F, G, or I of this part,

every allocation, transfer, or deduction

of a NOX allowance to or from the

compliance accounts of the NOX Budget

units covered by the permit or the

overdraft account of the NOX Budget

source covered by the permit.

§ 96.24 Effective date of initial NOX Budget

permit.

The initial NOX Budget permit

covering a NOX Budget unit for which

a complete NOX Budget permit

application is timely submitted under

§ 96.21(b) shall become effective by the

later of:

(a) May 1, 2003;

(b) May 1 of the year in which the

NOX Budget unit commences operation,

if the unit commences operation on or

before May 1 of that year;

(c) The date on which the NOX Budget

unit commences operation, if the unit

commences operation during a control

period; or

(d) May 1 of the year following the

year in which the NOX Budget unit

commences operation, if the unit

commences operation on or after

October 1 of the year.

§ 96.25 NOX Budget permit revisions.

(a) For a NOX Budget source with a

title V operating permit, except as

provided in § 96.23(b), the permitting

authority will revise the NOX Budget

permit, as necessary, in accordance with

the permitting authority’s title V

operating permits regulations

addressing permit revisions.

(b) For a NOX Budget source with a

non-title V permit, except as provided

in § 96.23(b), the permitting authority

will revise the NOX Budget permit, as

necessary, in accordance with the

permitting authority’s non-title V

permits regulations addressing permit

revisions.

Subpart D—Compliance Certification

§ 96.30 Compliance certification report.

(a) Applicability and deadline. For

each control period in which one or

more NOX Budget units at a source are

subject to the NOX Budget emissions

limitation, the NOX authorized account

representative of the source shall submit

to the permitting authority and the

Administrator by November 30 of that

year, a compliance certification report

for each source covering all such units.

(b) Contents of report. The NOX

authorized account representative shall

include in the compliance certification

report under paragraph (a) of this

section the following elements, in a

format prescribed by the Administrator,

concerning each unit at the source and

subject to the NOX Budget emissions

limitation for the control period covered

by the report:

(1) Identification of each NOX Budget

unit;
57524 Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations

(2) At the NOX authorized account

representative’s option, the serial

numbers of the NOX allowances that are

to be deducted from each unit’s

compliance account under § 96.54 for

the control period;

(3) At the NOX authorized account

representative’s option, for units sharing

a common stack and having NOX

emissions that are not monitored

separately or apportioned in accordance

with subpart H of this part, the

percentage of allowances that is to be

deducted from each unit’s compliance

account under § 96.54(e); and

(4) The compliance certification

under paragraph (c) of this section.

(c) Compliance certification. In the

compliance certification report under

paragraph (a) of this section, the NOX

authorized account representative shall

certify, based on reasonable inquiry of

those persons with primary

responsibility for operating the source

and the NOX Budget units at the source

in compliance with the NOX Budget

Trading Program, whether each NOX

Budget unit for which the compliance

certification is submitted was operated

during the calendar year covered by the

report in compliance with the

requirements of the NOX Budget

Trading Program applicable to the unit,

including:

(1) Whether the unit was operated in

compliance with the NOX Budget

emissions limitation;

(2) Whether the monitoring plan that

governs the unit has been maintained to

reflect the actual operation and

monitoring of the unit, and contains all

information necessary to attribute NOX

emissions to the unit, in accordance

with subpart H of this part;

(3) Whether all the NOX emissions

from the unit, or a group of units

(including the unit) using a common

stack, were monitored or accounted for

through the missing data procedures

and reported in the quarterly monitoring

reports, including whether conditional

data were reported in the quarterly

reports in accordance with subpart H of

this part. If conditional data were

reported, the owner or operator shall

indicate whether the status of all

conditional data has been resolved and

all necessary quarterly report

resubmissions has been made;

(4) Whether the facts that form the

basis for certification under subpart H of

this part of each monitor at the unit or

a group of units (including the unit)

using a common stack, or for using an

excepted monitoring method or

alternative monitoring method approved

under subpart H of this part, if any, has

changed; and

(5) If a change is required to be

reported under paragraph (c)(4) of this

section, specify the nature of the

change, the reason for the change, when

the change occurred, and how the unit’s

compliance status was determined

subsequent to the change, including

what method was used to determine

emissions when a change mandated the

need for monitor recertification.

§ 96.31 Permitting authority’s and

Administrator’s action on compliance

certifications.

(a) The permitting authority or the

Administrator may review and conduct

independent audits concerning any

compliance certification or any other

submission under the NOX Budget

Trading Program and make appropriate

adjustments of the information in the

compliance certifications or other

submissions.

(b) The Administrator may deduct

NOX allowances from or transfer NOX

allowances to a unit’s compliance

account or a source’s overdraft account

based on the information in the

compliance certifications or other

submissions, as adjusted under

paragraph (a) of this section.

Subpart E—NOX Allowance Allocations

§ 96.40 State trading program budget.

The State trading program budget

allocated by the permitting authority

under § 96.42 for a control period will

equal the total number of tons of NOX

emissions apportioned to the NOX

Budget units under § 96.4 in the State

for the control period, as determined by

the applicable, approved State

implementation plan.

§ 96.41 Timing requirements for NOX

allowance allocations.

(a) By September 30, 1999, the

permitting authority will submit to the

Administrator the NOX allowance

allocations, in accordance with § 96.42,

for the control periods in 2003, 2004,

and 2005.

(b) By April 1, 2003 and April 1 of

each year thereafter, the permitting

authority will submit to the

Administrator the NOX allowance

allocations, in accordance with § 96.42,

for the control period in the year that is

three years after the year of the

applicable deadline for submission

under this paragraph (b). If the

permitting authority fails to submit to

the Administrator the NOX allowance

allocations in accordance with this

paragraph (b), the Administrator will

allocate, for the applicable control

period, the same number of NOX

allowances as were allocated for the

preceding control period.

(c) By April 1, 2004 and April 1 of

each year thereafter, the permitting

authority will submit to the

Administrator the NOX allowance

allocations, in accordance with § 96.42,

for any NOX allowances remaining in

the allocation set-aside for the prior

control period.

§ 96.42 NOX allowance allocations.

(a)(1) The heat input (in mmBtu) used

for calculating NOX allowance

allocations for each NOX Budget unit

under § 96.4 will be:

(i) For a NOX allowance allocation

under § 96.41(a), the average of the two

highest amounts of the unit’s heat input

for the control periods in 1995, 1996,

and 1997 if the unit is under § 96.4(a)(1)

or the control period in 1995 if the unit

is under § 96.4(a)(2); and

(ii) For a NOX allowance allocation

under § 96.41(b), the unit’s heat input

for the control period in the year that is

four years before the year for which the

NOX allocation is being calculated.

(2) The unit’s total heat input for the

control period in each year specified

under paragraph (a)(1) of this section

will be determined in accordance with

part 75 of this chapter if the NOX Budget

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.

(b) For each control period under

§ 96.41, the permitting authority will

allocate to all NOX Budget units under

§ 96.4(a)(1) in the State that commenced

operation before May 1 of the period

used to calculate heat input under

paragraph (a)(1) of this section, a total

number of NOX allowances equal to 95

percent in 2003, 2004, and 2005, or 98

percent thereafter, of the tons of NOX

emissions in the State trading program

budget apportioned to electric

generating units under § 96.40 in

accordance with the following

procedures:

(1) The permitting authority will

allocate NOX allowances to each NOX

Budget unit under § 96.4(a)(1) in an

amount equaling 0.15 lb/mmBtu

multiplied by the heat input determined

under paragraph (a) of this section,

rounded to the nearest whole NOX

allowance as appropriate.

(2) If the initial total number of NOX

allowances allocated to all NOX Budget

units under § 96.4(a)(1) in the State for

a control period under paragraph (b)(1)

of this section does not equal 95 percent

in 2003, 2004, and 2005, or 98 percent

thereafter, of the number of tons of NOX

emissions in the State trading program
Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations 57525

budget apportioned to electric

generating units, the permitting

authority will adjust the total number of

NOX allowances allocated to all such

NOX Budget units for the control period

under paragraph (b)(1) of this section so

that the total number of NOX allowances

allocated equals 95 percent in 2003,

2004, and 2005, or 98 percent thereafter,

of the number of tons of NOX emissions

in the State trading program budget

apportioned to electric generating units.

This adjustment will be made by:

multiplying each unit’s allocation by 95

percent in 2003, 2004, and 2005, or 98

percent thereafter, of the number of tons

of NOX emissions in the State trading

program budget apportioned to electric

generating units divided by the total

number of NOX allowances allocated

under paragraph (b)(1) of this section,

and rounding to the nearest whole NOX

allowance as appropriate.

(c) For each control period under

§ 96.41, the permitting authority will

allocate to all NOX Budget units under

§ 96.4(a)(2) in the State that commenced

operation before May 1 of the period

used to calculate heat input under

paragraph (a)(1) of this section, a total

number of NOX allowances equal to 95

percent in 2003, 2004, and 2005, or 98

percent thereafter, of the tons of NOX

emissions in the State trading program

budget apportioned to non-electric

generating units under § 96.40 in

accordance with the following

procedures:

(1) The permitting authority will

allocate NOX allowances to each NOX

Budget unit under § 96.4(a)(2) in an

amount equaling 0.17 lb/mmBtu

multiplied by the heat input determined

under paragraph (a) of this section,

rounded to the nearest whole NOX

allowance as appropriate.

(2) If the initial total number of NOX

allowances allocated to all NOX Budget

units under § 96.4(a)(2) in the State for

a control period under paragraph (c)(1)

of this section does not equal 95 percent

in 2003, 2004, and 2005, or 98 percent

thereafter, of the number of tons of NOX

emissions in the State trading program

budget apportioned to non-electric

generating units, the permitting

authority will adjust the total number of

NOX allowances allocated to all such

NOX Budget units for the control period

under paragraph (c)(1) of this section so

that the total number of NOX allowances

allocated equals 95 percent in 2003,

2004, and 2005, or 98 percent thereafter,

of the number of tons of NOX emissions

in the State trading program budget

apportioned to non-electric generating

units. This adjustment will be made by:

multiplying each unit’s allocation by 95

percent in 2003, 2004, and 2005, or 98

percent thereafter, of the number of tons

of NOX emissions in the State trading

program budget apportioned to nonelectric generating units divided by the

total number of NOX allowances

allocated under paragraph (c)(1) of this

section, and rounding to the nearest

whole NOX allowance as appropriate.

(d) For each control period under

§ 96.41, the permitting authority will

allocate NOX allowances to NOX Budget

units under § 96.4 in the State that

commenced operation, or is projected to

commence operation, on or after May 1

of the period used to calculate heat

input under paragraph (a)(1) of this

section, in accordance with the

following procedures:

(1) The permitting authority will

establish one allocation set-aside for

each control period. Each allocation setaside will be allocated NOX allowances

equal to 5 percent in 2003, 2004, and

2005, or 2 percent thereafter, of the tons

of NOX emissions in the State trading

program budget under § 96.40, rounded

to the nearest whole NOX allowance as

appropriate.

(2) The NOX authorized account

representative of a NOX Budget unit

under paragraph (d) of this section may

submit to the permitting authority a

request, in writing or in a format

specified by the permitting authority, to

be allocated NOX allowances for no

more than five consecutive control

periods under § 96.41, starting with the

control period during which the NOX

Budget unit commenced, or is projected

to commence, operation and ending

with the control period preceding the

control period for which it will receive

an allocation under paragraph (b) or (c)

of this section. The NOX allowance

allocation request must be submitted

prior to May 1 of the first control period

for which the NOX allowance allocation

is requested and after the date on which

the permitting authority issues a permit

to construct the NOX Budget unit.

(3) In a NOX allowance allocation

request under paragraph (d)(2) of this

section, the NOX authorized account

representative for units under

§ 96.4(a)(1) may request for a control

period NOX allowances in an amount

that does not exceed 0.15 lb/mmBtu

multiplied by the NOX Budget unit’s

maximum design heat input (in mmBtu/

hr) multiplied by the number of hours

remaining in the control period starting

with the first day in the control period

on which the unit operated or is

projected to operate.

(4) In a NOX allowance allocation

request under paragraph (d)(2) of this

section, the NOX authorized account

representative for units under

§ 96.4(a)(2) may request for a control

period NOX allowances in an amount

that does not exceed 0.17 lb/mmBtu

multiplied by the NOX Budget unit’s

maximum design heat input (in mmBtu/

hr) multiplied by the number of hours

remaining in the control period starting

with the first day in the control period

on which the unit operated or is

projected to operate.

(5) The permitting authority will

review, and allocate NOX allowances

pursuant to, each NOX allowance

allocation request under paragraph

(d)(2) of this section in the order that the

request is received by the permitting

authority.

(i) Upon receipt of the NOX allowance

allocation request, the permitting

authority will determine whether, and

will make any necessary adjustments to

the request to ensure that, for units

under § 96.4(a)(1), the control period

and the number of allowances specified

are consistent with the requirements of

paragraphs (d)(2) and (3) of this section

and, for units under § 96.4(a)(2), the

control period and the number of

allowances specified are consistent with

the requirements of paragraphs (d)(2)

and (4) of this section.

(ii) If the allocation set-aside for the

control period for which NOX

allowances are requested has an amount

of NOX allowances not less than the

number requested (as adjusted under

paragraph (d)(5)(i) of this section), the

permitting authority will allocate the

amount of the NOX allowances

requested (as adjusted under paragraph

(d)(5)(i) of this section) to the NOX

Budget unit.

(iii) If the allocation set-aside for the

control period for which NOX

allowances are requested has a smaller

amount of NOX allowances than the

number requested (as adjusted under

paragraph (d)(5)(i) of this section), the

permitting authority will deny in part

the request and allocate only the

remaining number of NOX allowances in

the allocation set-aside to the NOX

Budget unit.

(iv) Once an allocation set-aside for a

control period has been depleted of all

NOX allowances, the permitting

authority will deny, and will not

allocate any NOX allowances pursuant

to, any NOX allowance allocation

request under which NOX allowances

have not already been allocated for the

control period.

(6) Within 60 days of receipt of a NOX

allowance allocation request, the

permitting authority will take

appropriate action under paragraph

(d)(5) of this section and notify the NOX

authorized account representative that

submitted the request and the

Administrator of the number of NOX
57526 Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations

allowances (if any) allocated for the

control period to the NOX Budget unit.

(e) For a NOX Budget unit that is

allocated NOX allowances under

paragraph (d) of this section for a

control period, the Administrator will

deduct NOX allowances under § 96.54(b)

or (e) to account for the actual

utilization of the unit during the control

period. The Administrator will calculate

the number of NOX allowances to be

deducted to account for the unit’s actual

utilization using the following formulas

and rounding to the nearest whole NOX

allowance as appropriate, provided that

the number of NOX allowances to be

deducted shall be zero if the number

calculated is less than zero:

NOX allowances deducted for actual

utilization for units under § 96.4(a)(1) =

(Unit’s NOX allowances allocated for

control period)¥(Unit’s actual control

period utilization × 0.15 lb/mmBtu); and

NOX allowances deducted for actual

utilization for units under § 96.4(a)(2) =

(Unit’s NOX allowances allocated for

control period)¥(Unit’s actual control

period utilization × 0.17 lb/mmBtu)

Where:

‘‘Unit’s NOX allowances allocated for

control period’’ is the number of NOX

allowances allocated to the unit for the

control period under paragraph (d) of this

section; and

‘‘Unit’s actual control period utilization’’ is

the utilization (in mmBtu), as defined in

§ 96.2, of the unit during the control period.

(f) After making the deductions for

compliance under § 96.54(b) or (e) for a

control period, the Administrator will

notify the permitting authority whether

any NOX allowances remain in the

allocation set-aside for the control

period. The permitting authority will

allocate any such NOX allowances to the

NOX Budget units in the State using the

following formula and rounding to the

nearest whole NOX allowance as

appropriate:

Unit’s share of NOX allowances remaining in

allocation set-aside = Total NOX

allowances remaining in allocation setaside × (Unit’s NOX allowance allocation

÷ (State trading program budget

excluding allocation set-aside)

Where:

‘‘Total NOX allowances remaining in

allocation set-aside’’ is the total number of

NOX allowances remaining in the allocation

set-aside for the control period to which the

allocation set-aside applies;

‘‘Unit’s NOX allowance allocation’’ is the

number of NOX allowances allocated under

paragraph (b) or (c) of this section to the unit

for the control period to which the allocation

set-aside applies; and

‘‘State trading program budget excluding

allocation set-aside’’ is the State trading

program budget under § 96.40 for the control

period to which the allocation set-aside

applies multiplied by 95 percent if the

control period is in 2003, 2004, or 2005 or

98 percent if the control period is in any year

thereafter, rounded to the nearest whole NOX

allowance as appropriate.

Subpart F—NOX Allowance Tracking

System

§ 96.50 NOX Allowance Tracking System

accounts.

(a) Nature and function of compliance

accounts and overdraft accounts.

Consistent with § 96.51(a), the

Administrator will establish one

compliance account for each NOX

Budget unit and one overdraft account

for each source with one or more NOX

Budget units. Allocations of NOX

allowances pursuant to subpart E of this

part or § 96.88 and deductions or

transfers of NOX allowances pursuant to

§ 96.31, § 96.54, § 96.56, subpart G of

this part, or subpart I of this part will

be recorded in the compliance accounts

or overdraft accounts in accordance

with this subpart.

(b) Nature and function of general

accounts. Consistent with § 96.51(b), the

Administrator will establish, upon

request, a general account for any

person. Transfers of allowances

pursuant to subpart G of this part will

be recorded in the general account in

accordance with this subpart.

§ 96.51 Establishment of accounts.

(a) Compliance accounts and

overdraft accounts. Upon receipt of a

complete account certificate of

representation under § 96.13, the

Administrator will establish:

(1) A compliance account for each

NOX Budget unit for which the account

certificate of representation was

submitted; and

(2) An overdraft account for each

source for which the account certificate

of representation was submitted and

that has two or more NOX Budget units.

(b) General accounts. (1) Any person

may apply to open a general account for

the purpose of holding and transferring

allowances. 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:

(i) Name, mailing address, e-mail

address (if any), telephone number, and

facsimile transmission number (if any)

of the NOX authorized account

representative and any alternate NOX

authorized account representative;

(ii) At the option of the NOX

authorized account representative,

organization name and type of

organization;

(iii) A list of all persons subject to a

binding agreement for the NOX

authorized account representative or

any alternate NOX authorized account

representative to represent their

ownership interest with respect to the

allowances held in the general account;

(iv) The following certification

statement by the NOX authorized

account representative and any alternate

NOX authorized account representative:

‘‘I certify that I was selected as the NOX

authorized account representative or the

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

NOX Budget 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.’’

(v) The signature of the NOX

authorized account representative and

any alternate NOX authorized account

representative and the dates signed.

(vi) Unless otherwise required by the

permitting authority or the

Administrator, documents of agreement

referred to in the account 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.

(2) 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 NOX authorized account

representative and any alternate 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 NOX allowances

held in the general account in all

matters pertaining to the NOX Budget

Trading Program, not withstanding any

agreement between the NOX authorized

account representative or any alternate

NOX authorized account representative

and such person. Any such person shall

be bound by any order or decision

issued to the NOX authorized account

representative or any alternate NOX

authorized account representative by
Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations 57527

the Administrator or a court regarding

the general account.

(iii) Each submission concerning the

general account shall be submitted,

signed, and certified by the NOX

authorized account representative or

any alternate NOX authorized account

representative for the persons having an

ownership interest with respect to NOX

allowances held in the general account.

Each such submission shall include the

following certification statement by the

NOX authorized account representative

or any alternate NOX authorized account

representative any: ‘‘I am authorized to

make this submission on behalf of the

persons having an ownership interest

with respect to the 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.’’

(iv) 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)(iii) of

this section.

(3)(i) An application for a general

account may designate one and only one

NOX authorized account representative

and one and only one alternate NOX

authorized account representative who

may act on behalf of the NOX authorized

account representative. The agreement

by which the alternate NOX authorized

account representative is selected shall

include a procedure for authorizing the

alternate NOX authorized account

representative to act in lieu of the NOX

authorized account representative.

(ii) Upon receipt by the Administrator

of a complete application for a general

account under paragraph (b)(1) of this

section, any representation, action,

inaction, or submission by any alternate

NOX authorized account representative

shall be deemed to be a representation,

action, inaction, or submission by the

NOX authorized account representative.

(4)(i) The 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 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

NOX authorized account representative

and the persons with an ownership

interest with respect to the allowances

in the general account.

(ii) The alternate 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 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 NOX authorized

account representative and the persons

with an ownership interest with respect

to the allowances in the general

account.

(iii)(A) In the event a new person

having an ownership interest with

respect to NOX allowances in the

general account is not included in the

list of such persons in the account

certificate of representation, such new

person shall be deemed to be subject to

and bound by the account certificate of

representation, the representation,

actions, inactions, and submissions of

the NOX authorized account

representative and any alternate NOX

authorized account representative of the

source or unit, 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 NOX

allowances in the general account,

including the addition of persons, the

NOX authorized account representative

or any alternate 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

NOX allowances in the general account

to include the change.

(5)(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)(4) of this section, no objection or

other communication submitted to the

Administrator concerning the

authorization, or any representation,

action, inaction, or submission of the

NOX authorized account representative

or any alternate NOX authorized account

representative for a general account

shall affect any representation, action,

inaction, or submission of the NOX

authorized account representative or

any alternate NOX authorized account

representative or the finality of any

decision or order by the Administrator

under the NOX Budget Trading Program.

(iii) The Administrator will not

adjudicate any private legal dispute

concerning the authorization or any

representation, action, inaction, or

submission of the NOX authorized

account representative or any alternate

NOX authorized account representative

for a general account, including private

legal disputes concerning the proceeds

of 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.

§ 96.52 NOX Allowance Tracking System

responsibilities of NOX authorized account

representative.

(a) Following the establishment of a

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 NOX allowances in the

account, shall be made only by the NOX

authorized account representative for

the account.

(b) Authorized account representative

identification. The Administrator will

assign a unique identifying number to

each NOX authorized account

representative.

§ 96.53 Recordation of NOX allowance

allocations.

(a) The Administrator will record the

NOX allowances for 2003 in the NOX

Budget units’ compliance accounts and

the allocation set-asides, as allocated

under subpart E of this part. The

Administrator will also record the NOX

allowances allocated under § 96.88(a)(1)

for each NOX Budget opt-in source in its

compliance account.

(b) Each year, after the Administrator

has made all deductions from a NOX

Budget unit’s compliance account and

the overdraft account pursuant to

§ 96.54, the Administrator will record
57528 Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations

NOX allowances, as allocated to the unit

under subpart E of this part or under

§ 96.88(a)(2), in the compliance account

for the year after the last year for which

allowances were previously allocated to

the compliance account. Each year, the

Administrator will also record NOX

allowances, as allocated under subpart E

of this part, in the allocation set-aside

for the year after the last year for which

allowances were previously allocated to

an allocation set-aside.

(c) Serial numbers for allocated NOX

allowances. When allocating NOX

allowances to and recording them in an

account, the Administrator will assign

each NOX allowance a unique

identification number that will include

digits identifying the year for which the

NOX allowance is allocated.

§ 96.54 Compliance.

(a) NOX allowance transfer deadline.

The NOX allowances are available to be

deducted for compliance with a unit’s

NOX Budget emissions limitation for a

control period in a given year only if the

NOX allowances:

(1) Were allocated for a control period

in a prior year or the same year; and

(2) Are held in the unit’s compliance

account, or the overdraft account of the

source where the unit is located, as of

the NOX allowance transfer deadline for

that control period or are transferred

into the compliance account or

overdraft account by a NOX allowance

transfer correctly submitted for

recordation under § 96.60 by the NOX

allowance transfer deadline for that

control period.

(b) Deductions for compliance. (1)

Following the recordation, in

accordance with § 96.61, of NOX

allowance transfers submitted for

recordation in the unit’s compliance

account or the overdraft account of the

source where the unit is located by the

NOX allowance transfer deadline for a

control period, the Administrator will

deduct NOX allowances available under

paragraph (a) of this section to cover the

unit’s NOX emissions (as determined in

accordance with subpart H of this part),

or to account for actual utilization under

§ 96.42(e), for the control period:

(i) From the compliance account; and

(ii) Only if no more NOX allowances

available under paragraph (a) of this

section remain in the compliance

account, from the overdraft account. In

deducting allowances for units at the

source from the overdraft account, the

Administrator will begin with the unit

having the compliance account with the

lowest NOX Allowance Tracking System

account number and end with the unit

having the compliance account with the

highest NOX Allowance Tracking

System account number (with account

numbers sorted beginning with the leftmost character and ending with the

right-most character and the letter

characters assigned values in

alphabetical order and less than all

numeric characters).

(2) The Administrator will deduct

NOX allowances first under paragraph

(b)(1)(i) of this section and then under

paragraph (b)(1)(ii) of this section:

(i) Until the number of NOX

allowances deducted for the control

period equals the number of tons of

NOX emissions, determined in

accordance with subpart H of this part,

from the unit for the control period for

which compliance is being determined,

plus the number of NOX allowances

required for deduction to account for

actual utilization under § 96.42(e) for

the control period; or

(ii) Until no more NOX allowances

available under paragraph (a) of this

section remain in the respective

account.

(c)(1) Identification of NOX

allowances by serial number. The NOX

authorized account representative for

each compliance account may identify

by serial number the NOX allowances to

be deducted from the unit’s compliance

account under paragraph (b), (d), or (e)

of this section. Such identification shall

be made in the compliance certification

report submitted in accordance with

§ 96.30.

(2) First-in, first-out. The

Administrator will deduct NOX

allowances for a control period from the

compliance account, in the absence of

an identification or in the case of a

partial identification of NOX allowances

by serial number under paragraph (c)(1)

of this section, or the overdraft account

on a first-in, first-out (FIFO) accounting

basis in the following order:

(i) Those NOX allowances that were

allocated for the control period to the

unit under subpart E or I of this part;

(ii) Those NOX allowances that were

allocated for the control period to any

unit and transferred and recorded in the

account pursuant to subpart G of this

part, in order of their date of

recordation;

(iii) Those NOX allowances that were

allocated for a prior control period to

the unit under subpart E or I of this part;

and

(iv) Those NOX allowances that were

allocated for a prior control period to

any unit and transferred and recorded in

the account pursuant to subpart G of

this part, in order of their date of

recordation.

(d) Deductions for excess emissions.

(1) After making the deductions for

compliance under paragraph (b) of this

section, the Administrator will deduct

from the unit’s compliance account or

the overdraft account of the source

where the unit is located a number of

NOX allowances, allocated for a control

period after the control period in which

the unit has excess emissions, equal to

three times the number of the unit’s

excess emissions.

(2) If the compliance account or

overdraft account does not contain

sufficient NOX allowances, the

Administrator will deduct the required

number of NOX allowances, regardless

of the control period for which they

were allocated, whenever NOX

allowances are recorded in either

account.

(3) Any allowance deduction required

under paragraph (d) of this section shall

not affect the liability of the owners and

operators of the NOX Budget unit for

any fine, penalty, or assessment, or their

obligation to comply with any other

remedy, for the same violation, as

ordered under the CAA 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 NOX

Budget unit has excess emissions for a

control period, each day in the control

period (153 days) constitutes a day in

violation unless the owners and

operators of the unit demonstrate that a

lesser number of days should be

considered.

(ii) Each ton of excess emissions is a

separate violation.

(e) Deductions for units sharing a

common stack. In the case of units

sharing a common stack and having

emissions that are not separately

monitored or apportioned in accordance

with subpart H of this part:

(1) The NOX authorized account

representative of the units may identify

the percentage of NOX allowances to be

deducted from each such unit’s

compliance account to cover the unit’s

share of NOX emissions from the

common stack for a control period. Such

identification shall be made in the

compliance certification report

submitted in accordance with § 96.30.

(2) Notwithstanding paragraph

(b)(2)(i) of this section, the

Administrator will deduct NOX

allowances for each such unit until the

number of NOX allowances deducted

equals the unit’s identified percentage

(under paragraph (e)(1) of this section)

of the number of tons of NOX emissions,

as determined in accordance with

subpart H of this part, from the common

stack for the control period for which

compliance is being determined or, if no

percentage is identified, an equal
Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations 57529

percentage for each such unit, plus the

number of allowances required for

deduction to account for actual

utilization under § 96.42(e) for the

control period.

(f) The Administrator will record in

the appropriate compliance account or

overdraft account all deductions from

such an account pursuant to paragraphs

(b), (d), or (e) of this section.

§ 96.55 Banking.

(a) NOX allowances may be banked for

future use or transfer in a compliance

account, an overdraft account, or a

general account, as follows:

(1) Any NOX allowance that is held in

a compliance account, an overdraft

account, or a general account will

remain in such account unless and until

the NOX allowance is deducted or

transferred under § 96.31, § 96.54,

§ 96.56, subpart G of this part, or

subpart I of this part.

(2) The Administrator will designate,

as a ‘‘banked’’ NOX allowance, any NOX

allowance that remains in a compliance

account, an overdraft account, or a

general account after the Administrator

has made all deductions for a given

control period from the compliance

account or overdraft account pursuant

to § 96.54.

(b) Each year starting in 2004, after

the Administrator has completed the

designation of banked NOX allowances

under paragraph (a)(2) of this section

and before May 1 of the year, the

Administrator will determine the extent

to which banked NOX allowances may

be used for compliance in the control

period for the current year, as follows:

(1) The Administrator will determine

the total number of banked NOX

allowances held in compliance

accounts, overdraft accounts, or general

accounts.

(2) If the total number of banked NOX

allowances determined, under

paragraph (b)(1) of this section, to be

held in compliance accounts, overdraft

accounts, or general accounts is less

than or equal to 10% of the sum of the

State trading program budgets for the

control period for the States in which

NOX Budget units are located, any

banked NOX allowance may be

deducted for compliance in accordance

with § 96.54.

(3) If the total number of banked NOX

allowances determined, under

paragraph (b)(1) of this section, to be

held in compliance accounts, overdraft

accounts, or general accounts exceeds

10% of the sum of the State trading

program budgets for the control period

for the States in which NOX Budget

units are located, any banked allowance

may be deducted for compliance in

accordance with § 96.54, except as

follows:

(i) The Administrator will determine

the following ratio: 0.10 multiplied by

the sum of the State trading program

budgets for the control period for the

States in which NOX Budget units are

located and divided by the total number

of banked NOX allowances determined,

under paragraph (b)(1) of this section, to

be held in compliance accounts,

overdraft accounts, or general accounts.

(ii) The Administrator will multiply

the number of banked NOX allowances

in each compliance account or overdraft

account. The resulting product is the

number of banked NOX allowances in

the account that may be deducted for

compliance in accordance with § 96.54.

Any banked NOX allowances in excess

of the resulting product may be

deducted for compliance in accordance

with § 96.54, except that, if such NOX

allowances are used to make a

deduction, two such NOX allowances

must be deducted for each deduction of

one NOX allowance required under

§ 96.54.

(c) Any NOX Budget unit may reduce

its NOX emission rate in the 2001 or

2002 control period, the owner or

operator of the unit may request early

reduction credits, and the permitting

authority may allocate NOX allowances

in 2003 to the unit in accordance with

the following requirements.

(1) Each NOX Budget unit for which

the owner or operator requests any early

reduction credits under paragraph (c)(4)

of this section shall monitor NOX

emissions in accordance with subpart H

of this part starting in the 2000 control

period and for each control period for

which such early reduction credits are

requested. The unit’s monitoring system

availability shall be not less than 90

percent during the 2000 control period,

and the unit must be in compliance

with any applicable State or Federal

emissions or emissions-related

requirements.

(2) NOX emission rate and heat input

under paragraphs (c)(3) through (5) of

this section shall be determined in

accordance with subpart H of this part.

(3) Each NOX Budget unit for which

the owner or operator requests any early

reduction credits under paragraph (c)(4)

of this section shall reduce its NOX

emission rate, for each control period

for which early reduction credits are

requested, to less than both 0.25 lb/

mmBtu and 80 percent of the unit’s NOX

emission rate in the 2000 control period.

(4) The NOX authorized account

representative of a NOX Budget unit that

meets the requirements of paragraphs

(c)(1)and (3) of this section may submit

to the permitting authority a request for

early reduction credits for the unit

based on NOX emission rate reductions

made by the unit in the control period

for 2001 or 2002 in accordance with

paragraph (c)(3) of this section.

(i) In the early reduction credit

request, the NOX authorized account

may request early reduction credits for

such control period in an amount equal

to the unit’s heat input for such control

period multiplied by the difference

between 0.25 lb/mmBtu and the unit’s

NOX emission rate for such control

period, divided by 2000 lb/ton, and

rounded to the nearest ton.

(ii) The early reduction credit request

must be submitted, in a format specified

by the permitting authority, by October

31 of the year in which the NOX

emission rate reductions on which the

request is based are made or such later

date approved by the permitting

authority.

(5) The permitting authority will

allocate NOX allowances, to NOX Budget

units meeting the requirements of

paragraphs (c)(1) and (3) of this section

and covered by early reduction requests

meeting the requirements of paragraph

(c)(4)(ii) of this section, in accordance

with the following procedures:

(i) Upon receipt of each early

reduction credit request, the permitting

authority will accept the request only if

the requirements of paragraphs (c)(1),

(c)(3), and (c)(4)(ii) of this section are

met and, if the request is accepted, will

make any necessary adjustments to the

request to ensure that the amount of the

early reduction credits requested meets

the requirement of paragraphs (c)(2) and

(4) of this section.

(ii) If the State’s compliance

supplement pool has an amount of NOX

allowances not less than the number of

early reduction credits in all accepted

early reduction credit requests for 2001

and 2002 (as adjusted under paragraph

(c)(5)(i) of this section), the permitting

authority will allocate to each NOX

Budget unit covered by such accepted

requests one allowance for each early

reduction credit requested (as adjusted

under paragraph (c)(5)(i) of this section).

(iii) If the State’s compliance

supplement pool has a smaller amount

of NOX allowances than the number of

early reduction credits in all accepted

early reduction credit requests for 2001

and 2002 (as adjusted under paragraph

(c)(5)(i) of this section), the permitting

authority will allocate NOX allowances

to each NOX Budget unit covered by
57530 Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations

such accepted requests according to the

following formula:

Unit’s allocated early reduction credits =

[(Unit’s adjusted early reduction credits)

/ (Total adjusted early reduction credits

requested by all units)] x (Available NOX

allowances from the State’s compliance

supplement pool)

where:

‘‘Unit’s adjusted early reduction credits’’ is

the number of early reduction credits for the

unit for 2001 and 2002 in accepted early

reduction credit requests, as adjusted under

paragraph (c)(5)(i) of this section.

‘‘Total adjusted early reduction credits

requested by all units’’ is the number of early

reduction credits for all units for 2001 and

2002 in accepted early reduction credit

requests, as adjusted under paragraph (c)(5)(i)

of this section.

‘‘Available NOX allowances from the

State’s compliance supplement pool’’ is the

number of NOX allowances in the State’s

compliance supplement pool and available

for early reduction credits for 2001 and 2002.

(6) By May 1, 2003, the permitting

authority will submit to the

Administrator the allocations of NOX

allowances determined under paragraph

(c)(5) of this section. The Administrator

will record such allocations to the

extent that they are consistent with the

requirements of paragraphs (c)(1)

through (5) of this section.

(7) NOX allowances recorded under

paragraph (c)(6) of this section may be

deducted for compliance under § 96.54

for the control periods in 2003 or 2004.

Notwithstanding paragraph (a) of this

section, the Administrator will deduct

as retired any NOX allowance that is

recorded under paragraph (c)(6) of this

section and is not deducted for

compliance in accordance with § 96.54

for the control period in 2003 or 2004.

(8) NOX allowances recorded under

paragraph (c)(6) of this section are

treated as banked allowances in 2004 for

the purposes of paragraphs (a) and (b) of

this section.

§ 96.56 Account error.

The Administrator may, at his or her

sole discretion and on his or her own

motion, correct any error in any NOX

Allowance Tracking System account.

Within 10 business days of making such

correction, the Administrator will notify

the NOX authorized account

representative for the account.

§ 96.57 Closing of general accounts.

(a) The NOX authorized account

representative of a general account may

instruct the Administrator to close the

account by submitting a statement

requesting deletion of the account from

the NOX Allowance Tracking System

and by correctly submitting for

recordation under § 96.60 an allowance

transfer of all NOX allowances in the

account to one or more other NOX

Allowance Tracking System accounts.

(b) If a general account shows no

activity for a period of a year or more

and does not contain any NOX

allowances, the Administrator may

notify the NOX authorized account

representative for the account that the

account will be closed and deleted from

the NOX Allowance Tracking System

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 NOX allowances

into the account under § 96.60 or a

statement submitted by the NOX

authorized account representative

demonstrating to the satisfaction of the

Administrator good cause as to why the

account should not be closed.

Subpart G—NOX Allowance Transfers

§ 96.60 Submission of NOX allowance

transfers.

The NOX authorized account

representatives seeking recordation of a

NOX allowance transfer shall submit the

transfer to the Administrator. To be

considered correctly submitted, the 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) A specification by serial number of

each NOX allowance to be transferred;

and

(c) The printed name and signature of

the NOX authorized account

representative of the transferor account

and the date signed.

§ 96.61 EPA recordation.

(a) Within 5 business days of

receiving a NOX allowance transfer,

except as provided in paragraph (b) of

this section, the Administrator will

record a NOX allowance transfer by

moving each NOX allowance from the

transferor account to the transferee

account as specified by the request,

provided that:

(1) The transfer is correctly submitted

under § 96.60;

(2) The transferor account includes

each NOX allowance identified by serial

number in the transfer; and

(3) The transfer meets all other

requirements of this part.

(b) A NOX allowance transfer that is

submitted for recordation following the

NOX allowance transfer deadline and

that includes any NOX allowances

allocated for a control period prior to or

the same as the control period to which

the NOX allowance transfer deadline

applies will not be recorded until after

completion of the process of recordation

of NOX allowance allocations in

§ 96.53(b).

(c) Where a NOX allowance transfer

submitted for recordation fails to meet

the requirements of paragraph (a) of this

section, the Administrator will not

record such transfer.

§ 96.62 Notification.

(a) Notification of recordation. Within

5 business days of recordation of a NOX

allowance transfer under § 96.61, the

Administrator will notify each party to

the transfer. Notice will be given to the

NOX authorized account representatives

of both the transferror and transferee

accounts.

(b) Notification of non-recordation.

Within 10 business days of receipt of a

NOX allowance transfer that fails to

meet the requirements of § 96.61(a), the

Administrator will notify the 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 NOX

allowance transfer for recordation

following notification of nonrecordation.

Subpart H—Monitoring and Reporting

§ 96.70 General requirements.

The owners and operators, and to the

extent applicable, the NOX authorized

account representative of a NOX Budget

unit, shall comply with the monitoring

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 § 96.2 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 replaced by the terms ‘‘NOX Budget

unit,’’ ‘‘NOX authorized account

representative,’’ and ‘‘continuous

emission monitoring system’’ (or

‘‘CEMS’’), respectively, as defined in

§ 96.2.

(a) Requirements for installation,

certification, and data accounting. The

owner or operator of each NOX Budget

unit must meet the following

requirements. These provisions also

apply to a unit for which an application

for a NOX Budget opt-in permit is

submitted and not denied or withdrawn,

as provided in subpart I of this part:

(1) Install all monitoring systems

required under this subpart for
Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations 57531

monitoring NOX mass. This includes all

systems required to monitor NOX

emission rate, NOX concentration, heat

input, and flow, in accordance with

§§ 75.72 and 75.76.

(2) Install all monitoring systems for

monitoring heat input, if required under

§ 96.76 for developing NOX allowance

allocations.

(3) Successfully complete all

certification tests required under § 96.71

and meet all other provisions of this

subpart and part 75 of this chapter

applicable to the monitoring systems

under paragraphs (a)(1) and (2) of this

section.

(4) Record, and report data from the

monitoring systems under paragraphs

(a)(1) and (2) of this section.

(b) Compliance dates. The owner or

operator must meet the requirements of

paragraphs (a)(1) through (a)(3) of this

section on or before the following dates

and must record and report data on and

after the following dates:

(1) NOX Budget units for which the

owner or operator intends to apply for

early reduction credits under § 96.55(d)

must comply with the requirements of

this subpart by May 1, 2000.

(2) Except for NOX Budget units under

paragraph (b)(1) of this section, NOX

Budget units under § 96.4 that

commence operation before January 1,

2002, must comply with the

requirements of this subpart by May 1,

2002.

(3) NOX Budget units under § 96.4

that commence operation on or after

January 1, 2002 and that report on an

annual basis under § 96.74(d) must

comply with the requirements of this

subpart by the later of the following

dates:

(i) May 1, 2002; or

(ii) The earlier of:

(A) 180 days after the date on which

the unit commences operation or, (B)

For units under § 96.4(a)(1), 90 days

after the date on which the unit

commences commercial operation.

(4) NOX Budget units under § 96.4

that commence operation on or after

January 1, 2002 and that report on a

control season basis under § 96.74(d)

must comply with the requirements of

this subpart by the later of the following

dates:

(i) The earlier of:

(A) 180 days after the date on which

the unit commences operation or,

(B) For units under § 96.4(a)(1), 90

days after the date on which the unit

commences commercial operation.

(ii) However, if the applicable

deadline under paragraph (b)(4)(i)

section does not occur during a control

period, May 1; immediately following

the date determined in accordance with

paragraph (b)(4)(i) of this section.

(5) For a NOX Budget unit with a new

stack or flue for which construction is

completed after the applicable deadline

under paragraph ( b)(1), (b)(2) or (b)(3)

of this section or subpart I of this part:

(i) 90 days after the date on which

emissions first exit to the atmosphere

through the new stack or flue;

(ii) However, if the unit reports on a

control season basis under § 96.74(d)

and the applicable deadline under

paragraph (b)(5)(i) of this section does

not occur during the control period,

May 1 immediately following the

applicable deadline in paragraph

(b)(5)(i) of this section.

(6) For a unit for which an application

for a NOX Budget opt in permit is

submitted and not denied or withdrawn,

the compliance dates specified under

subpart I of this part.

(c) Reporting data prior to initial

certification. (1) The owner or operator

of a NOX Budget unit that misses the

certification deadline under paragraph

(b)(1) of this section is not eligible to

apply for early reduction credits. The

owner or operator of the unit becomes

subject to the certification deadline

under paragraph (b)(2) of this section.

(2) The owner or operator of a NOX

Budget under paragraphs (b)(3) or (b)(4)

of this section must determine, record

and report NOX mass, heat input (if

required for purposes of allocations) and

any other values required to determine

NOX Mass (e.g. NOX emission rate and

heat input or NOX concentration and

stack flow) using the provisions of

§ 75.70(g) of this chapter, from the date

and hour that the unit starts operating

until all required certification tests are

successfully completed.

(d) Prohibitions. (1) No owner or

operator of a NOX Budget unit or a nonNOX Budget unit monitored under

§ 75.72(b)(2)(ii) 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 § 96.75.

(2) No owner or operator of a NOX

Budget unit or a non-NOX Budget unit

monitored under § 75.72(b)(2)(ii) 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

except as provided for in § 75.74 of this

chapter.

(3) No owner or operator of a NOX

Budget unit or a non-NOX Budget unit

monitored under § 75.72(b)(2)(ii) 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

except as provided for in § 75.74 of this

chapter.

(4) No owner or operator of a NOX

Budget unit or a non-NOX Budget unit

monitored under § 75.72(b)(2)(ii) shall

retire or permanently discontinue use of

the continuous emission monitoring

system, any component thereof, or any

other approved emission monitoring

system under this subpart, except under

any one of the following circumstances:

(i) During the period that the unit is

covered by a retired unit exemption

under § 96.5 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 NOX authorized account

representative submits notification of

the date of certification testing of a

replacement monitoring system in

accordance with § 96.71(b)(2).

§ 96.71 Initial certification and

recertification procedures

(a) The owner or operator of a NOX

Budget unit that is subject to an Acid

Rain emissions limitation shall comply

with the initial certification and

recertification procedures of part 75 of

this chapter, except that:

(1) If, prior to January 1, 1998, the

Administrator 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 of this chapter, the NOX

authorized account representative shall

resubmit the petition to the

Administrator under § 96.75(a) to

determine if the approval applies under

the NOX Budget Trading Program.

(2) For any additional CEMS required

under the common stack provisions in

§ 75.72 of this chapter, or for any NOX

concentration CEMS used under the

provisions of § 75.71(a)(2) of this

chapter, the owner or operator shall
57532 Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations

meet the requirements of paragraph (b)

of this section.

(b) The owner or operator of a NOX

Budget unit that is not subject to an

Acid Rain emissions limitation shall

comply with the following initial

certification and recertification

procedures, except that the owner or

operator of a unit that qualifies to use

the low mass emissions excepted

monitoring methodology under § 75.19

shall also meet the requirements of

paragraph (c) of this section and the

owner or operator of a unit that qualifies

to use an alternative monitoring system

under subpart E of part 75 of this

chapter shall also meet the requirements

of paragraph (d) of this section. The

owner or operator of a NOX Budget unit

that is subject to an Acid Rain emissions

limitation, but requires additional

CEMS under the common stack

provisions in § 75.72 of this chapter, or

that uses a NOX concentration CEMS

under § 75.71(a)(2) of this chapter also

shall comply with the following initial

certification and recertification

procedures.

(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 (which includes the

automated data acquisition and

handling system) successfully

completes all of the initial certification

testing required under § 75.20 of this

chapter. The owner or operator shall

ensure that all applicable certification

tests are successfully completed by the

deadlines specified in § 96.70(b). In

addition, whenever the owner or

operator installs a monitoring system in

order to meet the requirements of this

part in a location where no such

monitoring system was previously

installed, initial certification according

to § 75.20 is required.

(2) Requirements for recertification.

Whenever the owner or operator makes

a replacement, modification, or change

in a certified monitoring system that the

Administrator or the permitting

authority determines significantly

affects the ability of the system to

accurately measure or record NOX mass

emissions or heat input 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 according to

§ 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 the Administrator

or the permitting authority determines

to significantly change the flow or

concentration profile, the owner or

operator shall recertify the continuous

emissions monitoring system according

to § 75.20(b) of this chapter. Examples of

changes which require recertification

include: replacement of the analyzer,

change in location or orientation of the

sampling probe or site, or changing of

flow rate monitor polynomial

coefficients.

(3) Certification approval process for

initial certifications and recertification.

(i) Notification of certification. The NOX

authorized account representative shall

submit to the permitting authority, the

appropriate EPA Regional Office and the

permitting authority a written notice of

the dates of certification in accordance

with § 96.73.

(ii) Certification application. The NOX

authorized account 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

subpart H of part 75 of this chapter.

(iii) Except for units using the low

mass emission excepted methodology

under § 75.19 of this chapter, the

provisional certification date for a

monitor shall be determined using the

procedures set forth in § 75.20(a)(3) of

this chapter. A provisionally certified

monitor may be used under the NOX

Budget 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 or component

thereof under paragraph (b)(3)(ii) of this

section. Data measured and recorded by

the provisionally certified monitoring

system or component thereof, 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 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 (b)(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

which 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 NOX Budget 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 (b)(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 NOX

authorized account representative must

submit the additional information

required to complete the certification

application. If the NOX authorized

account 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

(b)(3)(iv)(C) of this section.

(C) Disapproval notice. If the

certification application shows that any

monitoring system or component

thereof does not meet the performance

requirements of this part, or if the

certification application is incomplete

and the requirement for disapproval

under paragraph (b)(3)(iv)(B) of this

section has been met, 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 or

component thereof shall not be

considered valid quality-assured data

beginning with the date and hour of

provisional certification. The owner or

operator shall follow the procedures for

loss of certification in paragraph

(b)(3)(v) of this section for each

monitoring system or component

thereof which 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

§ 96.72(b).

(v) Procedures for loss of certification.

If the permitting authority issues a

notice of disapproval of a certification

application under paragraph
Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations 57533

(b)(3)(iv)(C) of this section or a notice of

disapproval of certification status under

paragraph (b)(3)(iv)(D) of this section,

then:

(A) The owner or operator shall

substitute the following values, for each

hour of unit operation during the period

of invalid data beginning with the date

and hour of provisional certification and

continuing until the time, date, and

hour specified under § 75.20(a)(5)(i) of

this chapter:

(1) For units using or intending to

monitor for NOX emission rate and heat

input or for units using the low mass

emission excepted methodology under

§ 75.19 of this chapter, the maximum

potential NOX emission rate and the

maximum potential hourly heat input of

the unit.

(2) For units intending to monitor for

NOX mass emissions using a NOX

pollutant concentration monitor and a

flow monitor, the maximum potential

concentration of NOX and the maximum

potential flow rate of the unit under

section 2.1 of appendix A of part 75 of

this chapter;

(B) The NOX authorized account

representative shall submit a

notification of certification retest dates

and a new certification application in

accordance with paragraphs (b)(3)(i) and

(ii) of this section; and

(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.

(c) Initial certification and

recertification procedures for low mass

emission units using the excepted

methodologies under § 75.19 of this

chapter. The owner or operator of a gasfired or oil-fired unit using the low mass

emissions excepted methodology under

§ 75.19 of this chapter shall meet the

applicable general operating

requirements of § 75.10 of this chapter,

the applicable requirements of § 75.19 of

this chapter, and the applicable

certification requirements of § 96.71 of

this chapter, except that the excepted

methodology shall be deemed

provisionally certified for use under the

NOX Budget Trading Program, as of the

following dates:

(1) For units that are reporting on an

annual basis under § 96.74(d);

(i) For a unit that has commences

operation before its compliance

deadline under § 96.71(b), from January

1 of the year following submission of

the certification application for approval

to use the low mass emissions excepted

methodology under § 75.19 of this

chapter until the completion of the

period for the permitting authority

review; or

(ii) For a unit that commences

operation after its compliance deadline

under § 96.71(b), the date of submission

of the certification application for

approval to use the low mass emissions

excepted methodology under § 75.19 of

this chapter until the completion of the

period for permitting authority review,

or

(2) For units that are reporting on a

control period basis under

§ 96.74(b)(3)(ii) of this part:

(i) For a unit that commenced

operation before its compliance

deadline under § 96.71(b), where the

certification application is submitted

before May 1, from May 1 of the year of

the submission of the certification

application for approval to use the low

mass emissions excepted methodology

under § 75.19 of this chapter until the

completion of the period for the

permitting authority review; or

(ii) For a unit that commenced

operation before its compliance

deadline under § 96.71(b), where the

certification application is submitted

after May 1, from May 1 of the year

following submission of the certification

application for approval to use the low

mass emissions excepted methodology

under § 75.19 of this chapter until the

completion of the period for the

permitting authority review; or

(iii) For a unit that commences

operation after its compliance deadline

under § 96.71(b), where the unit

commences operation before May 1,

from May 1 of the year that the unit

commenced operation, until the

completion of the period for the

permitting authority’s review.

(iv) For a unit that has not operated

after its compliance deadline under

§ 96.71(b), where the certification

application is submitted after May 1, but

before October 1st, from the date of

submission of a certification application

for approval to use the low mass

emissions excepted methodology under

§ 75.19 of this chapter until the

completion of the period for the

permitting authority’s review.

(d) Certification/recertification

procedures for alternative monitoring

systems. The NOX authorized account

representative representing the owner or

operator of each unit applying to

monitor using an alternative monitoring

system approved by the Administrator

and, if applicable, the permitting

authority under subpart E of part 75 of

this chapter shall apply for certification

to the permitting authority prior to use

of the system under the NOX Trading

Program. The NOX authorized account

representative shall apply for

recertification following a replacement,

modification or change according to the

procedures in paragraph (b) of this

section. The owner or operator of an

alternative monitoring system shall

comply with the notification and

application requirements for

certification according to the procedures

specified in paragraph (b)(3) of this

section and § 75.20(f) of this chapter .

§ 96.72 Out of control periods.

(a) Whenever any monitoring system

fails to meet the quality assurance

requirements of appendix B of part 75

of this chapter, data shall be substituted

using the applicable procedures in

subpart D, 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 or component should not

have been certified or recertified

because it did not meet a particular

performance specification or other

requirement under § 96.71 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 or

component. 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 or component. The data

measured and recorded by the system or

component 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. The

owner or operator shall follow the

initial certification or recertification

procedures in § 96.71 for each

disapproved system.

§ 96.73 Notifications.

The NOX authorized account

representative for a NOX Budget 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.
57534 Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations

§ 96.74 Recordkeeping and reporting.

(a) General provisions. (1) The NOX

authorized account representative shall

comply with all recordkeeping and

reporting requirements in this section

and with the requirements of § 96.10(e).

(2) If the NOX authorized account

representative for a NOX Budget unit

subject to an Acid Rain Emission

limitation who signed and certified any

submission that is made under subpart

F or G of part 75 of this chapter and

which includes data and information

required under this subpart or subpart H

of part 75 of this chapter is not the same

person as the designated representative

or the alternative designated

representative for the unit under part 72

of this chapter, the submission must

also be signed by the designated

representative or the alternative

designated representative.

(b) Monitoring plans. (1) The owner or

operator of a unit subject to an Acid

Rain emissions limitation shall comply

with requirements of § 75.62 of this

chapter, except that the monitoring plan

shall also include all of the information

required by subpart H of part 75 of this

chapter.

(2) The owner or operator of a unit

that is not subject to an Acid Rain

emissions limitation shall comply with

requirements of § 75.62 of this chapter,

except that the monitoring plan is only

required to include the information

required by subpart H of part 75 of this

chapter.

(c) Certification applications. The

NOX authorized account representative

shall submit an application to the

permitting authority within 45 days

after completing all initial certification

or recertification tests required under

§ 96.71 including the information

required under subpart H of part 75 of

this chapter.

(d) Quarterly reports. The NOX

authorized account representative shall

submit quarterly reports, as follows:

(1) If a unit is subject to an Acid Rain

emission limitation or if the owner or

operator of the NOX budget unit chooses

to meet the annual reporting

requirements of this subpart H, the NOX

authorized account representative shall

submit a quarterly report for each

calendar quarter beginning with:

(i) For units that elect to comply with

the early reduction credit provisions

under § 96.55 of this part, the calender

quarter that includes the date of initial

provisional certification under

§ 96.71(b)(3)(iii). Data shall be reported

from the date and hour corresponding to

the date and hour of provisional

certification; or

(ii) For units commencing operation

prior to May 1, 2002 that are not

required to certify monitors by May 1,

2000 under § 96.70(b)(1), the earlier of

the calender quarter that includes the

date of initial provisional certification

under § 96.71(b)(3)(iii) or, if the

certification tests are not completed by

May 1, 2002, the partial calender quarter

from May 1, 2002 through June 30,

2002. Data shall be recorded and

reported from the earlier of the date and

hour corresponding to the date and hour

of provisional certification or the first

hour on May 1, 2002; or

(iii) For a unit that commences

operation after May 1, 2002, the

calendar quarter in which the unit

commences operation, Data shall be

reported from the date and hour

corresponding to when the unit

commenced operation.

(2) If a NOX budget unit is not subject

to an Acid Rain emission limitation,

then the NOX authorized account

representative shall either:

(i) Meet all of the requirements of part

75 related to monitoring and reporting

NOX mass emissions during the entire

year and meet the reporting deadlines

specified in paragraph (d)(1) of this

section; or

(ii) Submit quarterly reports only for

the periods from the earlier of May 1 or

the date and hour that the owner or

operator successfully completes all of

the recertification tests required under

§ 75.74(d)(3) through September 30 of

each year in accordance with the

provisions of § 75.74(b) of this chapter.

The NOX authorized account

representative shall submit a quarterly

report for each calendar quarter,

beginning with:

(A) For units that elect to comply with

the early reduction credit provisions

under § 96.55, the calender quarter that

includes the date of initial provisional

certification under § 96.71(b)(3)(iii).

Data shall be reported from the date and

hour corresponding to the date and hour

of provisional certification; or

(B) For units commencing operation

prior to May 1, 2002 that are not

required to certify monitors by May 1,

2000 under § 96.70(b)(1), the earlier of

the calender quarter that includes the

date of initial provisional certification

under § 96.71(b)(3)(iii), or if the

certification tests are not completed by

May 1, 2002, the partial calender quarter

from May 1, 2002 through June 30,

2002. Data shall be reported from the

earlier of the date and hour

corresponding to the date and hour of

provisional certification or the first hour

of May 1, 2002; or

(C) For units that commence

operation after May 1, 2002 during the

control period, the calender quarter in

which the unit commences operation.

Data shall be reported from the date and

hour corresponding to when the unit

commenced operation; or

(D) For units that commence

operation after May 1, 2002 and before

May 1 of the year in which the unit

commences operation, the earlier of the

calender quarter that includes the date

of initial provisional certification under

§ 96.71(b)(3)(iii) or, if the certification

tests are not completed by May 1 of the

year in which the unit commences

operation, May 1 of the year in which

the unit commences operation. Data

shall be reported from the earlier of the

date and hour corresponding to the date

and hour of provisional certification or

the first hour of May 1 of the year after

the unit commences operation.

(E) For units that commence operation

after May 1, 2002 and after September

30 of the year in which the unit

commences operation, the earlier of the

calender quarter that includes the date

of initial provisional certification under

§ 96.71(b)(3)(iii) or, if the certification

tests are not completed by May 1 of the

year after the unit commences

operation, May 1 of the year after the

unit commences operation. Data shall be

reported from the earlier of the date and

hour corresponding to the date and hour

of provisional certification or the first

hour of May 1 of the year after the unit

commences operation.

(3) The NOX authorized account

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 subpart H of

part 75 of this chapter and § 75.64 of

this chapter.

(i) For units subject to an Acid Rain

Emissions limitation, quarterly reports

shall include all of the data and

information required in subpart H of

part 75 of this chapter for each NOX

Budget unit (or group of units using a

common stack) as well as information

required in subpart G of part 75 of this

chapter.

(ii) For units not subject to an Acid

Rain Emissions limitation, quarterly

reports are only required to include all

of the data and information required in

subpart H of part 75 of this chapter for

each NOX Budget unit (or group of units

using a common stack).

(4) Compliance certification. The NOX

authorized account representative shall

submit to the Administrator a

compliance certification 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
Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations 57535

and fully monitored. The certification

shall state that:

(i) 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

(ii) For a unit with add-on NOX

emission controls and for all hours

where 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 monitoring plan

and the substitute values do not

systematically underestimate NOX

emissions; and

(iii) For a unit that is reporting on a

control period basis under § 96.74(d) the

NOX emission rate and NOX

concentration values substituted for

missing data under subpart D of part 75

of this chapter are calculated using only

values from a control period and do not

systematically underestimate NOX

emissions.

§ 96.75 Petitions.

(a) The NOX authorized account

representative of a NOX Budget 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.

(1) 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.

(2) Notwithstanding paragraph (a)(1)

of this section, if the petition requests

approval to apply an alternative to a

requirement concerning any additional

CEMS required under the common stack

provisions of § 75.72 of this chapter, the

petition is governed by paragraph (b) of

this section.

(b) The NOX authorized account

representative of a NOX Budget 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.

(1) The NOX authorized account

representative of a NOX Budget unit that

is 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 a requirement concerning

any additional CEMS required under the

common stack provisions of § 75.72 of

this chapter or a NOX concentration

CEMS used under 75.71(a)(2) of this

chapter.

(2) Application of an alternative to

any requirement of this subpart is in

accordance with this subpart only to the

extent the petition under paragraph (b)

of this section is approved by both the

permitting authority and the

Administrator.

§ 96.76 Additional requirements to provide

heat input data for allocations purposes.

(a) The owner or operator of a unit

that elects to monitor and report NOX

Mass emissions using a NOX

concentration system and a flow system

shall also monitor and report heat input

at the unit level using the procedures set

forth in part 75 of this chapter for any

source located in a state developing

source allocations based upon heat

input.

(b) The owner or operator of a unit

that monitor and report NOX Mass

emissions using a NOX concentration

system and a flow system shall also

monitor and report heat input at the

unit level using the procedures set forth

in part 75 of this chapter for any source

that is applying for early reduction

credits under § 96.55.

Subpart I—Individual Unit Opt-ins

§ 96.80 Applicability.

A unit that is in the State, is not a

NOX Budget unit under § 96.4, vents all

of its emissions to a stack, and is

operating, may qualify, under this

subpart, to become a NOX Budget optin source. A unit that is a NOX Budget

unit, is covered by a retired unit

exemption under § 96.5 that is in effect,

or is not operating is not eligible to

become a NOX Budget opt-in source.

§ 96.81 General.

Except otherwise as provided in this

part, a NOX Budget opt-in source shall

be treated as a NOX Budget unit for

purposes of applying subparts A

through H of this part.

§ 96.82 NOX authorized account

representative.

A unit for which an application for a

NOX Budget opt-in permit is submitted

and not denied or withdrawn, or a NOX

Budget opt-in source, located at the

same source as one or more NOX Budget

units, shall have the same NOX

authorized account representative as

such NOX Budget units.

§ 96.83 Applying for NOX Budget opt-in

permit.

(a) Applying for initial NOX Budget

opt-in permit. In order to apply for an

initial NOX Budget opt-in permit, the

NOX authorized account representative

of a unit qualified under § 96.80 may

submit to the permitting authority at

any time, except as provided under

§ 96.86(g):

(1) A complete NOX Budget permit

application under § 96.22;

(2) A monitoring plan submitted in

accordance with subpart H of this part;

and

(3) A complete account certificate of

representation under § 96.13, if no NOX

authorized account representative has

been previously designated for the unit.

(b) Duty to reapply. The NOX

authorized account representative of a

NOX Budget opt-in source shall submit

a complete NOX Budget permit

application under § 96.22 to renew the

NOX Budget opt-in permit in accordance

with § 96.21(c) and, if applicable, an

updated monitoring plan in accordance

with subpart H of this part.

§ 96.84 Opt-in process.

The permitting authority will issue or

deny a NOX Budget opt-in permit for a

unit for which an initial application for

a NOX Budget opt-in permit under

§ 96.83 is submitted, in accordance with

§ 96.20 and the following:

(a) Interim review of monitoring plan.

The permitting authority will

determine, on an interim basis, the

sufficiency of the monitoring plan

accompanying the initial application for

a NOX Budget opt-in permit under

§ 96.83. A monitoring plan is sufficient,

for purposes of interim review, if the

plan appears to contain information

demonstrating that the NOX emissions

rate and heat input of the unit are

monitored and reported in accordance

with subpart H of this part. A

determination of sufficiency shall not be

construed as acceptance or approval of

the unit’s monitoring plan.

(b) If the permitting authority

determines that the unit’s monitoring

plan is sufficient under paragraph (a) of

this section and after completion of

monitoring system certification under

subpart H of this part, the NOX

emissions rate and the heat input of the

unit shall be monitored and reported in

accordance with subpart H of this part

for one full control period during which

monitoring system availability is not

less than 90 percent and during which

the unit is in full compliance with any

applicable State or Federal emissions or

emissions-related requirements. Solely

for purposes of applying the

requirements in the prior sentence, the

unit shall be treated as a ‘‘NOX Budget

unit’’ prior to issuance of a NOX Budget

opt-in permit covering the unit.
57536 Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations

(c) Based on the information

monitored and reported under

paragraph (b) of this section, the unit’s

baseline heat rate shall be calculated as

the unit’s total heat input (in mmBtu)

for the control period and the unit’s

baseline NOX emissions rate shall be

calculated as the unit’s total NOX

emissions (in lb) for the control period

divided by the unit’s baseline heat rate.

(d) After calculating the baseline heat

input and the baseline NOX emissions

rate for the unit under paragraph (c) of

this section, the permitting authority

will serve a draft NOX Budget opt-in

permit on the NOX authorized account

representative of the unit.

(e) Confirmation of intention to opt-in.

Within 20 days after the issuance of the

draft NOX Budget opt-in permit, the

NOX authorized account representative

of the unit must submit to the

permitting authority a confirmation of

the intention to opt in the unit or a

withdrawal of the application for a NOX

Budget opt-in permit under § 96.83. The

permitting authority will treat the

failure to make a timely submission as

a withdrawal of the NOX Budget opt-in

permit application.

(f) Issuance of draft NOX Budget optin permit. If the NOX authorized account

representative confirms the intention to

opt-in the unit under paragraph (e) of

this section, the permitting authority

will issue the draft NOX Budget opt-in

permit in accordance with § 96.20.

(g) Notwithstanding paragraphs (a)

through (f) of this section, if at any time

before issuance of a draft NOX Budget

opt-in permit for the unit, the permitting

authority determines that the unit does

not qualify as a NOX Budget opt-in

source under § 96.80, the permitting

authority will issue a draft denial of a

NOX Budget opt-in permit for the unit

in accordance with § 96.20.

(h) Withdrawal of application for NOX

Budget opt-in permit. A NOX authorized

account representative of a unit may

withdraw its application for a NOX

Budget opt-in permit under § 96.83 at

any time prior to the issuance of the

final NOX Budget opt-in permit. Once

the application for a NOX Budget opt-in

permit is withdrawn, a NOX authorized

account representative wanting to

reapply must submit a new application

for a NOX Budget permit under § 96.83.

(i) Effective date. The effective date of

the initial NOX Budget opt-in permit

shall be May 1 of the first control period

starting after the issuance of the initial

NOX Budget opt-in permit by the

permitting authority. The unit shall be

a NOX Budget opt-in source and a NOX

Budget unit as of the effective date of

the initial NOX Budget opt-in permit.

§ 96.85 NOX Budget opt-in permit

contents.

(a) Each NOX Budget opt-in permit

(including any draft or proposed NOX

Budget opt-in permit, if applicable) will

contain all elements required for a

complete NOX Budget opt-in permit

application under § 96.22 as approved

or adjusted by the permitting authority.

(b) Each NOX Budget opt-in permit is

deemed to incorporate automatically the

definitions of terms under § 96.2 and,

upon recordation by the Administrator

under subpart F, G, or I of this part,

every allocation, transfer, or deduction

of NOX allowances to or from the

compliance accounts of each NOX

Budget opt-in source covered by the

NOX Budget opt-in permit or the

overdraft account of the NOX Budget

source where the NOX Budget opt-in

source is located.

§ 96.86 Withdrawal from NOX Budget

Trading Program.

(a) Requesting withdrawal. To

withdraw from the NOX Budget Trading

Program, the NOX authorized account

representative of a NOX Budget opt-in

source shall submit to the permitting

authority a request to withdraw effective

as of a specified date prior to May 1 or

after September 30. The submission

shall be made no later than 90 days

prior to the requested effective date of

withdrawal.

(b) Conditions for withdrawal. Before

a NOX Budget opt-in source covered by

a request under paragraph (a) of this

section may withdraw from the NOX

Budget Trading Program and the NOX

Budget opt-in permit may be terminated

under paragraph (e) of this section, the

following conditions must be met:

(1) For the control period immediately

before the withdrawal is to be effective,

the NOX authorized account

representative must submit or must

have submitted to the permitting

authority an annual compliance

certification report in accordance with

§ 96.30.

(2) If the NOX Budget opt-in source

has excess emissions for the control

period immediately before the

withdrawal is to be effective, the

Administrator will deduct or has

deducted from the NOX Budget opt-in

source’s compliance account, or the

overdraft account of the NOX Budget

source where the NOX Budget opt-in

source is located, the full amount

required under § 96.54(d) for the control

period.

(3) After the requirements for

withdrawal under paragraphs (b)(1) and

(2) of this section are met, the

Administrator will deduct from the NOX

Budget opt-in source’s compliance

account, or the overdraft account of the

NOX Budget source where the NOX

Budget opt-in source is located, NOX

allowances equal in number to and

allocated for the same or a prior control

period as any NOX allowances allocated

to that source under § 96.88 for any

control period for which the withdrawal

is to be effective. The Administrator will

close the NOX Budget opt-in source’s

compliance account and will establish,

and transfer any remaining allowances

to, a new general account for the owners

and operators of the NOX Budget opt-in

source. The NOX authorized account

representative for the NOX Budget optin source shall become the NOX

authorized account representative for

the general account.

(c) A NOX Budget opt-in source that

withdraws from the NOX Budget

Trading Program shall comply with all

requirements under the NOX Budget

Trading Program concerning all years

for which such NOX Budget opt-in

source was a NOX Budget opt-in source,

even if such requirements arise or must

be complied with after the withdrawal

takes effect.

(d) Notification. (1) After the

requirements for withdrawal under

paragraphs (a) and (b) of this section are

met (including deduction of the full

amount of NOX allowances required),

the permitting authority will issue a

notification to the NOX authorized

account representative of the NOX

Budget opt-in source of the acceptance

of the withdrawal of the NOX Budget

opt-in source as of a specified effective

date that is after such requirements have

been met and that is prior to May 1 or

after September 30.

(2) If the requirements for withdrawal

under paragraphs (a) and (b) of this

section are not met, the permitting

authority will issue a notification to the

NOX authorized account representative

of the NOX Budget opt-in source that the

NOX Budget opt-in source’s request to

withdraw is denied. If the NOX Budget

opt-in source’s request to withdraw is

denied, the NOX Budget opt-in source

shall remain subject to the requirements

for a NOX Budget opt-in source.

(e) Permit amendment. After the

permitting authority issues a

notification under paragraph (d)(1) of

this section that the requirements for

withdrawal have been met, the

permitting authority will revise the NOX

Budget permit covering the NOX Budget

opt-in source to terminate the NOX

Budget opt-in permit as of the effective

date specified under paragraph (d)(1) of

this section. A NOX Budget opt-in

source shall continue to be a NOX

Budget opt-in source until the effective

date of the termination.
Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations 57537

(f) Reapplication upon failure to meet

conditions of withdrawal. If the

permitting authority denies the NOX

Budget opt-in source’s request to

withdraw, the NOX authorized account

representative may submit another

request to withdraw in accordance with

paragraphs (a) and (b) of this section.

(g) Ability to return to the NOX Budget

Trading Program. Once a NOX Budget

opt-in source withdraws from the NOX

Budget Trading Program and its NOX

Budget opt-in permit is terminated

under this section, the NOX authority

account representative may not submit

another application for a NOX Budget

opt-in permit under § 96.83 for the unit

prior to the date that is 4 years after the

date on which the terminated NOX

Budget opt-in permit became effective.

§ 96.87 Change in regulatory status.

(a) Notification. When a NOX Budget

opt-in source becomes a NOX Budget

unit under § 96.4, the NOX authorized

account representative shall notify in

writing the permitting authority and the

Administrator of such change in the

NOX Budget opt-in source’s regulatory

status, within 30 days of such change.

(b) Permitting authority’s and

Administrator’s action. (1)(i) When the

NOX Budget opt-in source becomes a

NOX Budget unit under § 96.4, the

permitting authority will revise the NOX

Budget opt-in source’s NOX Budget optin permit to meet the requirements of a

NOX Budget permit under § 96.23 as of

an effective date that is the date on

which such NOX Budget opt-in source

becomes a NOX Budget unit under

§ 96.4.

(ii)(A) The Administrator will deduct

from the compliance account for the

NOX Budget unit under paragraph

(b)(1)(i) of this section, or the overdraft

account of the NOX Budget source

where the unit is located, NOX

allowances equal in number to and

allocated for the same or a prior control

period as:

(1) Any NOX allowances allocated to

the NOX Budget unit (as a NOX Budget

opt-in source) under § 96.88 for any

control period after the last control

period during which the unit’s NOX

Budget opt-in permit was effective; and

(2) If the effective date of the NOX

Budget permit revision under paragraph

(b)(1)(i) of this section is during a

control period, the NOX allowances

allocated to the NOX Budget unit (as a

NOX Budget opt-in source) under

§ 96.88 for the control period multiplied

by the ratio of the number of days, in

the control period, starting with the

effective date of the permit revision

under paragraph (b)(1)(i) of this section,

divided by the total number of days in

the control period.

(B) The NOX authorized account

representative shall ensure that the

compliance account of the NOX Budget

unit under paragraph (b)(1)(i) of this

section, or the overdraft account of the

NOX Budget source where the unit is

located, includes the NOX allowances

necessary for completion of the

deduction under paragraph (b)(1)(ii)(A)

of this section. If the compliance

account or overdraft account does not

contain sufficient NOX allowances, the

Administrator will deduct the required

number of NOX allowances, regardless

of the control period for which they

were allocated, whenever NOX

allowances are recorded in either

account.

(iii)(A) For every control period

during which the NOX Budget permit

revised under paragraph (b)(1)(i) of this

section is effective, the NOX Budget unit

under paragraph (b)(1)(i) of this section

will be treated, solely for purposes of

NOX allowance allocations under

§ 96.42, as a unit that commenced

operation on the effective date of the

NOX Budget permit revision under

paragraph (b)(1)(i) of this section and

will be allocated NOX allowances under

§ 96.42.

(B) Notwithstanding paragraph

(b)(1)(iii)(A) of this section, if the

effective date of the NOX Budget permit

revision under paragraph (b)(1)(i) of this

section is during a control period, the

following number of NOX allowances

will be allocated to the NOX Budget unit

under paragraph (b)(1)(i) of this section

under § 96.42 for the control period: the

number of NOX allowances otherwise

allocated to the NOX Budget unit under

§ 96.42 for the control period multiplied

by the ratio of the number of days, in

the control period, starting with the

effective date of the permit revision

under paragraph (b)(1)(i) of this section,

divided by the total number of days in

the control period.

(2)(i) When the NOX authorized

account representative of a NOX Budget

opt-in source does not renew its NOX

Budget opt-in permit under § 96.83(b),

the Administrator will deduct from the

NOX Budget opt-in unit’s compliance

account, or the overdraft account of the

NOX Budget source where the NOX

Budget opt-in source is located, NOX

allowances equal in number to and

allocated for the same or a prior control

period as any NOX allowances allocated

to the NOX Budget opt-in source under

§ 96.88 for any control period after the

last control period for which the NOX

Budget opt-in permit is effective. The

NOX authorized account representative

shall ensure that the NOX Budget opt-in

source’s compliance account or the

overdraft account of the NOX Budget

source where the NOX Budget opt-in

source is located includes the NOX

allowances necessary for completion of

such deduction. If the compliance

account or overdraft account does not

contain sufficient NOX allowances, the

Administrator will deduct the required

number of NOX allowances, regardless

of the control period for which they

were allocated, whenever NOX

allowances are recorded in either

account.

(ii) After the deduction under

paragraph (b)(2)(i) of this section is

completed, the Administrator will close

the NOX Budget opt-in source’s

compliance account. If any NOX

allowances remain in the compliance

account after completion of such

deduction and any deduction under

§ 96.54, the Administrator will close the

NOX Budget opt-in source’s compliance

account and will establish, and transfer

any remaining allowances to, a new

general account for the owners and

operators of the NOX Budget opt-in

source. The NOX authorized account

representative for the NOX Budget optin source shall become the NOX

authorized account representative for

the general account.

§ 96.88 NOX allowance allocations to optin units.

(a) NOX allowance allocation. (1) By

December 31 immediately before the

first control period for which the NOX

Budget opt-in permit is effective, the

permitting authority will allocate NOX

allowances to the NOX Budget opt-in

source and submit to the Administrator

the allocation for the control period in

accordance with paragraph (b) of this

section.

(2) By no later than December 31, after

the first control period for which the

NOX Budget opt-in permit is in effect,

and December 31 of each year thereafter,

the permitting authority will allocate

NOX allowances to the NOX Budget optin source, and submit to the

Administrator allocations for the next

control period, in accordance with

paragraph (b) of this section.

(b) For each control period for which

the NOX Budget opt-in source has an

approved NOX Budget opt-in permit, the

NOX Budget opt-in source will be

allocated NOX allowances in accordance

with the following procedures:

(1) The heat input (in mmBtu) used

for calculating NOX allowance

allocations will be the lesser of:

(i) The NOX Budget opt-in source’s

baseline heat input determined

pursuant to § 96.84(c); or
57538 Federal Register / Vol. 63, No. 207 /Tuesday, October 27, 1998 /Rules and Regulations

(ii) The NOX Budget opt-in source’s

heat input, as determined in accordance

with subpart H of this part, for the

control period in the year prior to the

year of the control period for which the

NOX allocations are being calculated.

(2) The permitting authority will

allocate NOX allowances to the NOX

Budget opt-in source in an amount

equaling the heat input (in mmBtu)

determined under paragraph (b)(1) of

this section multiplied by the lesser of:

(i) The NOX Budget opt-in source’s

baseline NOX emissions rate (in lb/

mmBtu) determined pursuant to

§ 96.84(c); or

(ii) The most stringent State or

Federal NOX emissions limitation

applicable to the NOX Budget opt-in

source during the control period.

Subpart J—Mobile and Area Sources

[Reserved]

[FR Doc. 98–26773 Filed 10–26–98; 8:45 am]

BILLING CODE 6560–01–P