25902 Federal Register / Vol. 63, No. 90 / Monday, May 11, 1998 / Proposed Rules

ENVIRONMENTAL PROTECTION

AGENCY

40 CFR Parts 51, 76, and 96

[FRL–6008–6]

RIN 2060–AH10

Supplemental Notice for the 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: Supplemental Notice of

Proposed Rulemaking (SNPR).

SUMMARY: In accordance with the Clean

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

to EPA’s November 7, 1997 notice of

proposed rulemaking (NPR). This action

augments EPA’s proposal to require

certain States to submit State

implementation plan (SIP) measures to

ensure that emissions reductions are

achieved as needed to mitigate transport

of ozone (smog) pollution and one of its

main precursors—emissions of oxides of

nitrogen (NOX)—across State boundaries

in the eastern half of the United States.

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.

Today’s action includes proposed rule

language for the November 7, 1997 NPR

for the 23 jurisdictions, revised

statewide emissions budgets and cost

analysis, proposed State reporting

requirements and SIP approvability

criteria, a proposed model cap-and-trade

rule, a discussion of the interaction

between this proposal and the title IV

NOX rule, and air quality analyses of the

proposed statewide emissions budgets.

The EPA intends to finalize today’s

action and the November 7, 1997 NPR

simultaneously in the September 1998

timeframe.

DATES: The EPA is establishing a 45-day

comment period, ending on June 25,

1998. Comments must be postmarked by

the last day of the comment period and

sent directly to the Docket Office listed

in ADDRESSES (in duplicate form if

possible). A public hearing will be held

on May 29, 1998, beginning at 9:00 am.

Please refer to SUPPLEMENTARY

INFORMATION for details.

ADDRESSES: Comments may be

submitted to the Air and Radiation

Docket and Information Center (6101),

Attention: Docket No. A–96–56, 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. Comments and

data may also be submitted

electronically by following the

instructions under SUPPLEMENTARY

INFORMATION of this document. No

Confidential Business Information (CBI)

should be submitted through e-mail. A

courtesy copy of comments to David

Cole would be appreciated at Office of

Air Quality Planning and Standards, Air

Quality Strategies and Standards

Division, MD–15, Research Triangle

Park, NC 27711, telephone (919) 541–

5565, Fax (919) 541–0824. An electronic

copy would also be helpful to

cole.david@epa.gov. The address for

sending overnight packages is US EPA,

Air Quality Strategies and Standards

Division, 411 W. Chapel Hill St.,

Durham, NC 27701. The public hearing

will be held at the EPA Auditorium at

401 M Street SW, Washington, DC,

20460.

FOR FURTHER INFORMATION CONTACT:

General questions concerning today’s

action should be addressed to Kimber

Smith 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. Please refer

to SUPPLEMENTARY INFORMATION below

for a list of contacts for specific subjects

described in today’s action.

SUPPLEMENTARY INFORMATION:

Reopening of November 7, 1997 NPR

Comment Period and Technical

Analyses

The Agency will ensure that all

comments and technical analyses

received on the November 7, 1997 NPR

(62 FR 60318) and this SNPR are made

publicly available in the docket to this

rulemaking. The EPA will accept

comments on all issues raised in today’s

SNPR, as well as comments concerning

the implications that any such issues

may have for issues raised in the

November 7, 1997 NPR. In addition, on

April 9, 1998 (63 FR 17349), EPA

published a notice in the Federal

Register that discussed additional items

related to the November 7, 1998 NPR for

which the Agency is reopening the

comment period. Therefore, the

comment period for the November 7,

1997 NPR is reopened until June 25,

1998 for the items specified in the April

9, 1998 notice.

Public Hearing

The EPA will conduct a public

hearing on today’s proposal on May 29,

1998 beginning at 9:00 a.m. The public

hearing will be held at the EPA

Auditorium at 401 M Street SW.,

Washington, DC 20460. The metro stop

is Waterfront which is on the green line.

Persons planning to present oral

testimony at the hearing should notify

JoAnn Allman, Office of Air Quality

Planning and Standards, Air Quality

Strategies and Standards Division, MD–

15, Research Triangle Park, NC 27711,

telephone (919) 541–1815 no later than

May 22, 1998. Oral testimony will be

limited to 5 minutes each. Any member

of the public may file a written

statement before, during, or by the close

of the comment period after the hearing.

For written statements concerning the

proposed amended 40 CFR Part 76, the

hearing record will be kept open for 30

days after the hearing date, under

section 307(d)(5)(iv) of the CAA to

provide an opportunity for submission

of rebuttal and supplementary

information. Written statements

(duplicate copies preferred) should be

submitted to the docket at the above

address. A hearing schedule including a

list of speakers will be posted on EPA’s

SIP call webpage at http://

www.epa.gov/ttn/oarpg/otagsip.html

prior to the hearing.

Following the hearing, a verbatim

transcript of the hearing and written

statements will be made available for

copying during normal working hours at

the Air and Radiation Docket

Information Center at the above address.

The Agency does not plan to schedule

any additional hearings on the proposed

rule.

Electronic Availability

The official record for this

rulemaking, as well as the public

version, has been established under

docket number A–96–56 (including

comments and data submitted

electronically as described below). A

public version of this record, including

printed, paper versions of electronic

comments, which does not include any

information claimed as CBI, is available

for inspection from 8 a.m. to 4 p.m.,

Monday through Friday, excluding legal

holidays. The official rulemaking record

is located at the address in ADDRESSES

at the beginning of this document.
Federal Register / Vol. 63, No. 90 / Monday, May 11, 1998 / Proposed Rules 25903

Electronic comments can be sent

directly to EPA at: A-and-RDocket@epamail.epa.gov. Electronic

comments must be submitted as an

ASCII file avoiding the use of special

characters and any form of encryption.

Comments and data will also be

accepted on disks in WordPerfect in 6.1

(or 5.1) file format or ASCII file format.

All comments and data in electronic

form must be identified by the docket

number A–96–56. Electronic comments

on this proposed rule may be filed

online at many Federal Depository

Libraries.

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

October 10, 1997 signature version of

the proposed SIP call, the November 7,

1997 Federal Register version, and

associated documents are located at

http://epa.gov/ttn/oarpg/otagsip.html.

Information related to Section VII, Air

Quality Assessment of the Statewide

Emissions Budgets can be obtained in

electronic form from the following EPA

website: http://www.epa.gov/scram001/

regmodcenter/t28.htm.

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

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,

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 November 7, 1997 NPR

B. Updates With 1994–96 Air Quality Data

for the Findings of Significant

Contribution

II. Proposed Rule for the 23 Jurisdictions

III. Emissions Budgets Analyses

A. Explanation of Revised Budgets

1. Electricity Generating Units

a. Addition of Sources

b. Growth Factors

c. Revised Budget Component

d. Alternative Approach to Calculating the

Component of the Budget for Electricity

Generation

2. Non-Electricity Generating Point Sources

a. Addition of Sources

b. Application of Controls

c. Revised Budget Component

d. Options for Calculating the Budgets

3. Revised State Budgets

B. Revised Cost Analyses

1. Electricity Generating Sources

2. Non-Electricity Generating Point Sources

3. Cost Analysis Results

IV. SIP Criteria and Emissions Reporting

Requirements

A. SIP Criteria

1. Introduction

2. Completeness Determination

3. Approvability Criteria

a. Additional Control Strategy

Approvability Criteria

i. Introduction

ii. General Recommendations

iii. New Proposed Approval Criteria

b. Emissions Inventory Preparation

Guidance and Control Strategies

Guidance

c. Growth Estimates

d. Emissions Growth and Projection

Guidance

B. Emissions Reporting Requirements

1. Use of Inventory Data

2. Legal Authority

3. Background for Reporting Requirements

4. Proposal

5. Annual Reporting

a. Point Sources

b. Area Sources

c. Mobile Sources

6. Reporting Every Third Year (3-year cycle

reporting)

7. 2007 Report

8. Ozone Season Reporting

9. Data Reporting Procedures

10. Reporting Schedule

11. Confidential Data

12. Data Elements to be Reported

V. NOX Budget Trading Program

A. Program Summary

1. Purpose of the NOX Budget Trading

Program

2. Emissions Reductions Required by the

Proposed Transport Rulemaking

3. Benefits of Participating in the NOX

Budget Trading Program

4. EPA’s Proposal

B. Evolution of the NOX Budget Trading

Program

1. OTC’s NOX Budget Program

2. OTAG Process

3. EPA Model Trading Program Workshops

4. RECLAIM Program

C. NOX Budget Trading Program

1. General Provisions

a. Purpose

b. Definitions, Measurements,

Abbreviations and Acronyms

c. Applicability

i. Monitoring

ii. Responsible Party

iii. Inclusion of Additional Source

Categories

iv. Individual Opt-Ins

v. Additional Options for Applicability

vi. Area and Mobile Sources

d. Retired Unit Exemption

e. Standard Requirements

f. Computation of Time

2. NOX Authorized Account Representative

(AAR)

3. Permits

a. General Requirements

b. Title V/Non-title V Permits

c. NOX Budget Permit Application

Deadlines

d. NOX Budget Trading Program Permit

Application

e. NOX Budget Permit Issuance

f. NOX Budget Permit Revisions

4. Compliance Certification

5. NOX Allowance Allocations

a. Development of State Trading Program

Budget

b. Timing Requirements

c. Options for NOX Allowance Allocation

Recommendation

i. Basis for Developing an Allocation

Recommendation

ii. Options for an Allocation

Recommendation

iii. Framework for an Allocation

Recommendation

6. NOX Allowance Tracking System

a. Compliance Accounts

b. Overdraft Accounts

c. Compliance

d. General Accounts

7. Banking

a. General Discussion

i. Banking After the Start of the Program

ii. Banking Prior to the Start of the Program

iii. Management of Banking

b. Options

i. Option 1: No Banking

ii. Option 2: Banking After Program Start

Only
25904 Federal Register / Vol. 63, No. 90 / Monday, May 11, 1998 / Proposed Rules

1The EPA signed the November 7, 1997 NPR on

October 10, 1997 and made it immediately available

to the public on EPA’s homepage at http://

www.epa.gov/ttn/oarpg/rules.html.

iii. Option 3: Early-Reduction Credits

iv. Option 4: Phased-In Program

8. Allowance Transfers

9. Emissions Monitoring and Reporting

a. Requirements for Point Sources

b. Output Information

10. Opt-Ins

a. Applicability for Opt-In Units

b. Allowance Allocations for Opt-In Units

c. Units Sharing Stacks or Fuel Pipe

Headers with NOX Budget Units

d. Withdrawal and Termination of Opt-In

Units

11. Program Audits

12. Administration of Program

D. SIP Approvability

E. OTC Integration

1. Applicability

a. State Applicability

b. Source Applicability

2. Allocations

3. Emissions Banking

4. Emissions Monitoring and Reporting

5. Permitting

F. New Source Review

G. End Use Energy Efficiency and

Renewable Energy

1. Background

2. Energy Efficiency and Renewables SetAside Options

VI. Interaction with Title IV NOX Rule

VII. Air Quality Assessment of the Statewide

Emissions Budgets Analyses

A. Background Information

B. Emissions Scenarios

1. Development of Emissions Inputs

a. Electric Generation Sources

b. Non-Electric Generation Point Sources

c. Mobile and Area Sources

2. Emissions Summaries

C. Analysis of Modeling Results

1. Technical Procedures

a. State-Level Analysis

i. Selection of Grid Cells for Analysis

ii. Procedures for Calculating State-Level

Metrics

b. OTAG Standard Table of Metrics

D. Analysis Results and Findings

1. Introduction

a. Impacts on 1-Hour Ozone

Concentrations

i. State-Level Analyses—1-Hour

Concentrations

ii. Ozone Problem Area Analyses—1-Hour

Concentrations

b. Impacts on 8-Hour Ozone

Concentrations

i. State-Level Analyses—8-Hour

Concentrations

ii. Ozone Problem Area Analyses—8-Hour

Concentrations

2. Summary and Conclusions

E. Alternative Approaches

VIII. Impact on Small Entities

IX. Unfunded Mandates Reform Act

X. Paperwork Reduction Act

XI. Judicial Review

I. Background

A. Summary of November 7, 1997 NPR

The EPA’s November 7, 1997

proposal 1 (hereafter referred to as the

‘‘proposed SIP call’’ or ‘‘SIP call’’)

proposed to find that the transport of

ozone and ozone precursors from 22

States and the District of Columbia (23

jurisdictions) significantly contributes

to nonattainment of the ozone national

ambient air quality standards (NAAQS),

or interferes with maintenance of the

NAAQS, in downwind States. The

proposed SIP call explained the basis

for determining significant contribution

or interference with maintenance for the

23 jurisdictions. Further, the SIP call

proposed the appropriate levels of NOX

emissions that each of the 23

jurisdictions would be required to

achieve. The EPA also conducted a

regulatory cost analysis which is

available in the docket to this

rulemaking (docket number II–B–01) as

a technical support document (TSD) to

the proposed SIP call. A detailed

explanation of how EPA established the

budgets is also available as a TSD to the

proposal (docket number III–B–02).

These TSDs have been revised as

explained in Section III, Emissions

Budgets Analyses.

The SIP call proposed SIP

requirements under CAA section

110(a)(1) and section 110(k)(5) in order

to meet the requirements of section

110(a)(2)(D), as it pertains to the ozone

NAAQS, to prohibit ozone precursor

emissions from sources or activities in

those States from ‘‘contribut[ing]

significantly to nonattainment in, or

interfer[ing] with maintenance by,’’ a

downwind State.

Based on this determination, the EPA

proposed to require SIP revisions in

order to take steps toward ensuring that

the necessary regional reductions are

achieved that will enable current ozone

nonattainment areas in the eastern half

of the United States to prepare

attainment demonstrations and that will

enable all areas to demonstrate

noninterference with maintenance of

the ozone standard. This requirement

permits each State to choose for itself

what measures to adopt to meet the

necessary emissions budget. Consistent

with OTAG’s recommendations to

achieve 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-andtrade program as a cost-effective

strategy. The cap-and-trade program is

described in more detail in Section V,

NOX Budget Trading Program.

B. Updates With 1994–96 Air Quality

Data for the Findings of Significant

Contribution

In the proposed SIP call, EPA

followed a weight of evidence approach

to determine which States cause a

significant contribution to

nonattainment in downwind States. Part

of the information EPA considered in

this determination included air quality

modeling based on the OTAG 2007 Base

Case and OTAG ‘‘zero-out’’ subregional

UAM–V simulations. The results of the

2007 Base Case modeling were analyzed

with 1993–1995 ambient air quality

measurements to identify areas which

(a) currently violate the NAAQS (based

on monitoring) and (b) are expected to

continue to violate the NAAQS in the

future (based on modeling). The ‘‘zeroout’’ subregional modeling data were

then used to quantify the ‘‘ppb’’

contributions to ozone in these

‘‘nonattainment’’ areas. The resulting

‘‘ppb’’ contributions were provided in

the SIP call Tables II–10 and II–12 for

the 1-hour and 8-hour NAAQS,

respectively.

The EPA stated in the SIP call that it

would review more recent air quality

data and, in the event that these data

alter the results of the significant

contribution assessment in any

meaningful way, EPA would make the

appropriate adjustments to the findings.

Since the SIP call was published, EPA

has reviewed 1996 air quality data to

determine which counties violate the 1-

hour and 8-hour NAAQS based on

1994–1996 measurements. A list of the

1-hour and 8-hour violating counties

based on these data is provided in the

docket. The EPA recalculated the ‘‘ppb’’

contributions to downwind

nonattainment using the 1994–1996 1-

hour and 8-hour violating counties and

the OTAG 2007 Base Case and ‘‘zeroout’’ subregional modeling. The

resulting updated 1-hour and 8-hour

contribution tables are provided in the

docket. Based upon a review of the

information in these tables, EPA finds

no basis for altering its conclusions on

significant contribution.

II. Proposed Action for the 23

Jurisdictions

This SNPR includes the proposed rule

language for the CFR for the basic

elements of the proposed SIP call,

including the requirements imposed on

the 23 jurisdictions to submit SIP

revisions, under both the 1-hour and 8-

hour standard, providing for

implementation of the applicable

statewide NOX emissions budget, as

well as the definition of the NOX
Federal Register / Vol. 63, No. 90 / Monday, May 11, 1998 / Proposed Rules 25905

budget. The rule language is located at

the end of the preamble.

III. Emissions Budgets Analyses

A. Explanation of Revised Budgets

A number of changes were made to

the emissions inventory used to

calculate the budget. These changes

apply to the electricity generating and

non-electricity generating point source

sectors only and were made to correct

errors found subsequent to publication

of the proposed SIP call (NPR). These

source sectors are discussed separately

below. Detailed information concerning

the changes can be found in the revised

Budget TSD titled ‘‘Development of

Modeling Inventory and Budgets for the

Ozone Transport SIP Call’’ (revised

Budget TSD).

1. Electricity Generating Units

The changes that were made to the

electricity generating component of the

budgets fall into two general categories:

addition of sources and changes in

growth factors. Both of these changes

increase the budgets.

a. Addition of Sources. The changes

that were made in the population of the

utility and non-utility owned electricity

generating units since the November 7,

1997 notice are summarized in Table

III–1. This SNPR includes 1,757 units

compared to 1,180 units in the NPR.

This reflects an addition of 577 units to

the State budget inventories. These

units include electricity generating

sources 25 megawatts of electrical

output (MWe) or smaller and additional

units not affected under the Acid Rain

Program (40 CFR part 76). Detailed

information on the sources of data for

these additional units is contained in

the revised Budget TSD.

TABLE III–1.—INVENTORY CHANGE

FROM NPR

Source NPR population

SNPR population

Utility ................. 1062 1510

Non-Utility .......... 118 247

Total ........... 1180 1757

b. Growth Factors. The EPA’s

‘‘Proposed Ozone Transport Rulemaking

Regulatory Analysis’’ (September 1997,

docket number III–B–01) used a 1995

forecast of future electricity demand

prepared by the North American

Electric Reliability Council (NERC),

with adjustments for EPA’s 1996

estimates of the electricity demand

reductions that the Climate Change

Action Plan (CCAP) was projected to

produce from the year 2000 and on.

Details on how EPA prepared this

electricity demand forecast can be found

in EPA’s ‘‘Analyzing Electric Power

Generation under the Clean Air Act,’’

(July 1996, docket number II–A–07).

The EPA used this electricity demand

forecast in analyses conducted for

OTAG and the Clean Air Power

Initiative (CAPI). Further, EPA also used

this forecast when establishing the

State-specific growth factors used in the

NPR (referred to as the ‘‘original’’

projections).

While EPA is continuing to use the

electricity generating industry growth

projections described in the NPR when

establishing the budget component for

that sector, this SNPR is correcting one

error in the growth factor calculation of

the NPR. The EPA corrected its

estimates of State-specific growth rates

from 1996 to 2007. The estimates were

interpolated from the average annual

growth of each State as forecasted by

EPA using the Integrated Planning

Model (IPM) and EPA’s baseline

electricity generation forecast. In

developing the average annual growth,

EPA relied on unit-specific summer

energy use from 2000 to 2010 as

forecasted by the IPM. The average

annual growth was determined using

the State-specific growth from 2000 to

2010. However, when calculating the

growth for the year 2010, EPA

inadvertently omitted information on

many of the new combustion turbine

and combined-cycle units that IPM

forecasts to be built by 2010. Thus new

electricity-generating capacity, expected

to be built between 2000 and 2010 was

not included when estimating the

industry growth between 2000 and

2010. This error resulted in an

underestimation of the expected average

annual growth for each affected State. In

the revision of the budget for the electric

power industry, this error has been

corrected. The change leads to a higher

electricity generating component of the

NOX budget for all affected States. The

corrected growth factors are shown in

Table III–2 (referred to as the

‘‘corrected’’ projections).

TABLE III–2.—CORRECTED ELECTRICITY GENERATION GROWTH FACTORS

State Original

96–07 factor

Corrected

96–07 factor

Percent

increase

Alabama ....................................................................................................................................... 1.03 1.16 12.92

Connecticut ................................................................................................................................... 0.92 1.22 32.99

District of Columbia ...................................................................................................................... 1.00 1.00 0.00

Delaware ...................................................................................................................................... 1.68 1.80 6.77

Georgia ......................................................................................................................................... 1.14 1.21 6.32

Illinois ............................................................................................................................................ 1.23 1.34 8.63

Indiana .......................................................................................................................................... 1.27 1.30 2.64

Kentucky ....................................................................................................................................... 1.20 1.28 6.41

Massachusetts .............................................................................................................................. 1.62 1.71 5.62

Maryland ....................................................................................................................................... 1.14 1.23 7.37

Michigan ....................................................................................................................................... 1.13 1.18 4.60

Missouri ........................................................................................................................................ 1.13 1.24 9.28

North Carolina .............................................................................................................................. 1.10 1.26 15.04

New Jersey ................................................................................................................................... 0.99 1.26 27.37

New York ...................................................................................................................................... 1.11 1.22 10.16

Ohio .............................................................................................................................................. 1.10 1.14 3.19

Pennsylvania ................................................................................................................................ 1.07 1.15 7.07

Rhode Island ................................................................................................................................ 0.43 0.48 11.83

South Carolina .............................................................................................................................. 1.32 1.63 23.22

Tennessee .................................................................................................................................... 0.92 1.25 35.78

Virginia .......................................................................................................................................... 1.18 1.43 20.50

Wisconsin ..................................................................................................................................... 1.07 1.13 6.30

West Virginia ................................................................................................................................ 1.02 1.05 3.26
25906 Federal Register / Vol. 63, No. 90 / Monday, May 11, 1998 / Proposed Rules

Since the NPR, EPA has also updated

its electricity demand forecast to

include more up-to-date information.

The information was obtained from the

same sources used in developing the

forecast used in the NPR. The EPA’s

more recent forecast uses the 1997

forecast of future electricity demand

prepared by NERC with adjustments for

the Administration’s 1997 estimates of

electricity demand reductions that the

CCAP is projected to produce from 2000

on (referred to as the ‘‘revised’’

projections). The EPA found that this

revised estimate leads to lower growth

rates for the electricity generating

industry than the estimate used in the

NPR analyses. However, in this SNPR,

EPA uses the corrected forecast when

calculating State-specific budgets

because of the inherent uncertainty in

any projection, and EPA’s willingness to

provide States flexibility in achieving

their budgets. Further, when evaluating

the cost effectiveness of NOX controls,

EPA considered both the corrected and

revised future electricity demand

forecasts. However, for all other

analyses under this SNPR, EPA is using

the corrected future electricity demand

forecast. Further, EPA solicits comment

on whether to use only the revised

future electricity demand forecast for

the budget and cost effectiveness

calculations.

c. Revised Budget Component. Both

the 2007 electricity generating Base Case

and the electricity generating Budget

component were revised based on the

changes described above. These

revisions are shown in Tables III–3 and

III–4. The difference between the 2007

Base Case and Budget emissions that

were proposed and the revised Base

Case and Budget emissions is shown in

Table III–3. The revised percent

reduction from the 2007 Base Case to

the Budget is shown in Table III–4.

TABLE III–3.—CHANGES TO PROPOSED BASE CASE AND BUDGET COMPONENTS FOR ELECTRICITY GENERATING UNITS

[tons NOX/season]

State Proposed

base

Revised

base

Percent

increase

Proposed

budget

Revised

budget

Percent

increase

Alabama ........................................................................................ 81,704 85,201 4 26,946 30,644 14

Connecticut ................................................................................... 5,715 7,048 23 3,409 5,245 54

Delaware ....................................................................................... 10,901 10,727 ¥2 4,390 4,994 14

District of Columbia ....................................................................... 385 236 ¥39 152 152 0

Georgia ......................................................................................... 92,946 84,890 ¥9 30,158 32,433 8

Illinois ............................................................................................ 115,053 119,756 4 31,833 36,570 15

Indiana .......................................................................................... 177,888 159,917 ¥10 48,791 51,818 6

Kentucky ....................................................................................... 128,688 130,919 2 35,820 38,775 8

Maryland ....................................................................................... 35,332 37,575 6 11,364 12,971 14

Massachusetts .............................................................................. 28,284 24,998 ¥12 12,956 14,651 13

Michigan ........................................................................................ 82,057 73,585 ¥10 25,402 29,458 16

Missouri ......................................................................................... 92,313 81,799 ¥11 22,932 26,450 15

New Jersey ................................................................................... 14,553 17,484 20 5,041 8,191 62

New York ...................................................................................... 39,639 43,705 10 24,653 31,222 27

North Carolina ............................................................................... 83,273 86,872 4 27,543 32,691 19

Ohio ............................................................................................... 185,757 167,601 ¥10 46,758 51,493 10

Pennsylvania ................................................................................. 125,195 120,979 ¥3 39,594 45,971 16

Rhode Island ................................................................................. 773 1,351 75 905 1,609 78

South Carolina .............................................................................. 43,363 57,146 32 15,090 19,842 31

Tennessee .................................................................................... 71,994 83,844 16 19,318 26,225 36

Virginia .......................................................................................... 45,719 51,113 12 16,884 20,990 24

West Virginia ................................................................................. 83,719 76,374 ¥9 23,306 24,045 3

Wisconsin ...................................................................................... 51,004 45,538 ¥11 15,755 17,345 10

Total ....................................................................................... 1,596,255 1,568,655 ¥2 489,000 563,784 15

TABLE III–4.—REVISED NOX BUDGET COMPONENTS AND PERCENT REDUCTION FOR ELECTRICITY GENERATING UNITS

[tons/season]

State Revised base Revised

budget

Percent

reduction

Alabama ....................................................................................................................................... 85,201 30,644 64

Connecticut ................................................................................................................................... 7,048 5,245 26

Delaware ...................................................................................................................................... 10,727 4,994 53

District of Columbia ...................................................................................................................... 236 152 36

Georgia ......................................................................................................................................... 84,890 32,433 62

Illinois ............................................................................................................................................ 119,756 36,570 69

Indiana .......................................................................................................................................... 159,917 51,818 68

Kentucky ....................................................................................................................................... 130,919 38,775 70

Maryland ....................................................................................................................................... 37,575 12,971 65

Massachusetts .............................................................................................................................. 24,998 14,651 41

Michigan ....................................................................................................................................... 73,585 29,458 60

Missouri ........................................................................................................................................ 81,799 26,450 68

New Jersey ................................................................................................................................... 17,484 8,191 53

New York ...................................................................................................................................... 43,705 31,222 29

North Carolina .............................................................................................................................. 86,872 32,691 62

Ohio .............................................................................................................................................. 167,601 51,493 69

Pennsylvania ................................................................................................................................ 120,979 45,971 62

Rhode Island ................................................................................................................................ 1,351 1,609 ¥19
Federal Register / Vol. 63, No. 90 / Monday, May 11, 1998 / Proposed Rules 25907

TABLE III–4.—REVISED NOX BUDGET COMPONENTS AND PERCENT REDUCTION FOR ELECTRICITY GENERATING UNITS—

Continued

[tons/season]

State Revised base Revised

budget

Percent

reduction

South Carolina .............................................................................................................................. 57,146 19,842 65

Tennessee .................................................................................................................................... 83,844 26,225 69

Virginia .......................................................................................................................................... 51,113 20,990 59

West Virginia ................................................................................................................................ 76,374 24,045 69

Wisconsin ..................................................................................................................................... 45,538 17,345 62

Total ...................................................................................................................................... 1,568,655 563,784 64

d. Alternative Approach to

Calculating the Component of the

Budget for Electricity Generation. In this

regulatory action, the component of

each State’s budget assigned to

electricity generation is determined

using the State’s total heat input,

applicable emission rate (0.15 lb/million

British thermal units per hour

(mmBtu)), and projected growth to 2007.

Consequently, for each State this budget

component is based on the amount of

fossil fuel each State uses to produce

electricity. However, States use other fuel sources

to generate electricity, notably nuclear

and hydro energy, as well as solar and

wind energy. Furthermore, some

facilities that rely on fossil fuel sources

are more efficient, in terms of lower

NOX emissions, than other facilities. In

addition, each State’s use of sources to

generate electricity may change over

time. For example, electricity now

produced by the combustion of fossil

fuels may, in the future, be produced

using alternative sources and vice versa. Because of the shifts in generation

from one fuel source to another, an

alternative approach to determining

each State’s share of the total

regionwide budget component based on

total heat input may be a consideration

of total electricity generation within the

State. Under this approach (referred to

as ‘‘output-based’’), the electricity

generation component (i.e., 563,784 tons

of NOX) of the regionwide budget would

be apportioned among the States based

on total electricity generation, not only

fossil-fuel generation. Since the total

regionwide budget component would be

the same as that proposed in this notice,

and assuming a multistate trading

program, the environmental effects and

cost effectiveness of such an allocation

should be similar to the proposed

approach. The data used to apportion the

regionwide budget component to each

State under the output-based approach

would be State-specific generation (in

MWh) for the time period May 1 to

September 30. One source of such

information is the Energy Information

Administration’s (EIA) Form 759, where

electricity generating sources report

their monthly generation. To more

equitably account for shifts from Stateto-State, it may be appropriate to use the

higher of summer 1995 or 1996

generation for each State in determining

the output-based State budget

components, or perhaps the average of

the highest two out of three summer

periods. The first approach is similar to

that used in generating the proposed

budget for this sector. This alternative approach has the

effect of rewarding States that have

invested in methods of electricity

generation that result in no, or fewer,

NOX emissions. At the same time,

because most electricity generation

relies on fossil-fuel inputs that, in turn,

result in NOX emissions, even under

this output-based approach, the State

budgets would bear a strong

relationship to amount of actual NOX

emissions on a State-by-State basis. Even so, the resulting budgets for each

State would be different, to some

degree, from the budgets currently

proposed. If a regionwide trading

program is ultimately used, it may be

assumed that emissions would be

reallocated so that each State’s budget

under the alternative approach would

be the same as under the currently

proposed approach. Of course, in this

case, the cost effectiveness and

environmental benefit associated with

this alternative approach would be the

same as that of the currently proposed

approach. It seems plausible to assume

that States subject to the NOX SIP call

would opt for regionwide trading due to

the cost effectiveness of this approach. However, in this rulemaking, EPA is

not attempting to require regionwide

trading, and if the States opt not to

employ such a system, the air quality

impacts of an output-based approach

and its cost effectiveness may be

different from the air quality impacts

under the proposed budget. If for some

States, the budget under the outputbased approach is significantly lower

than that under the proposed approach,

the absence of a regionwide trading

system may result in required control

levels that are not technically

achievable.

Other issues that arise under the

output-based approach concern the

representativeness and quality of the

required data. Specifically, the EIA data

used in the output-based approach may

not include all electricity generating

sources, such as Independent Power

Producers (IPPs) and Non-Utility

Generators (NUGs). Additionally, some

may argue that it is inappropriate to

incorporate the non-NOX-emitting

sources in the calculation of each State’s

electricity generation component of the

budget. In addition, the alternative

budget fails to consider the fact that

nuclear-, hydro-, solar-, or windpowered facilities generate steam

output, as well as electricity.

Accordingly, it may be logical to adjust

the alternative budgets further to take

account of steam output. Further, as

discussed in Section V.C.9.b, Output

Information, of this preamble, there are

a number of issues associated with

measuring and using electricity- or

steam-related output data. The EPA

solicits comments on all issues

concerning this alternative approach,

including the appropriateness, legality,

rationale, and methodology for

incorporating the output-based

approach when calculating the

electricity generation component of

each State’s budget.

2. Non-Electricity Generating Point

Sources

Changes that were made to the nonelectricity generating point source

component of the budgets fall into two

categories: addition of sources and

application of controls. Addition of

sources increases the budgets, while

correction in the application of controls

tends to decrease the budgets. a. Addition of Sources. Based on the

matching that was done to identify

electricity generating sources, it was

determined that a number of sources
25908 Federal Register / Vol. 63, No. 90 / Monday, May 11, 1998 / Proposed Rules

that were identified in the OTAG

inventory as utilities were, in fact, not

utility sources. In the budgets that were

proposed on November 7, 1997, these

sources were left out of the inventory

when the OTAG utility data were

replaced by the acid rain data. These

sources have since been identified and

added back into the budgets. A list of

the sources that were moved from the

electricity generating to non-electricity

generating sector is contained in the

revised Budget TSD.

b. Application of Controls. The nonelectricity generating point source

budget components were calculated

based on the OTAG recommendations

as follows:

• 70 percent control for large (> 250

mmBtu/hr) sources (measured from

uncontrolled 2007 emissions);

• Reasonably Available Control

Technology (RACT)-level controls for all

other NOX sources with more than 1.0

tons per day (tpd) of NOX emissions

(medium-sized sources);

• Small source NOX emissions were

estimated using OTAG Base 1c scenario

emission values.

For the budgets that were proposed,

RACT was erroneously applied only to

those sources that were in areas

required to adopt RACT. The intent of

the proposed approach was to apply

RACT to all medium-sized sources,

regardless of whether they are located in

an area that would otherwise be

required to apply RACT. The revised

budgets reflect the application of RACT

to all medium-sized sources in the

affected States. A list of the sources that

were treated as large and medium

sources is contained in the appendices

to the revised Budget TSD.

c. Revised Budget Component. Both

the 2007 Base Case and Budget

component for non-electricity

generating point sources were revised

based on the changes described above.

These revisions are shown in Tables III–

5 and III–6. The difference between the

2007 Base Case and Budget emissions

that were proposed and the revised Base

Case and Budget emissions for nonelectricity generating units is shown in

Table III–5. The revised percent

reduction from the 2007 Base Case to

the Budget is shown in Table III–6.

TABLE III–5.—CHANGES TO PROPOSED BASE CASE AND BUDGET COMPONENTS FOR NON-ELECTRICITY GENERATING

UNITS

[tons NOX/season]

Proposed

base

Revised

base

Percent

increase

Proposed

budget

Revised

budget

Percent

decrease

Alabama ........................................................................................ 47,182 48,187 2 25,131 24,416 3

Connecticut ................................................................................... 4,732 5,254 11 4,475 3,103 31

Delaware ....................................................................................... 5,205 5,276 1 3,206 2,271 29

District of Columbia ....................................................................... 312 311 0 312 259 17

Georgia ......................................................................................... 34,012 33,939 0 20,472 14,305 30

Illinois ............................................................................................ 63,642 65,351 3 39,855 40,719 –2

Indiana .......................................................................................... 51,432 51,839 1 35,603 29,187 18

Kentucky ....................................................................................... 18,817 19,019 1 12,258 11,996 2

Maryland ....................................................................................... 6,729 10,710 59 4,825 5,852 –21

Massachusetts .............................................................................. 10,683 9,978 –7 7,590 6,207 18

Michigan ........................................................................................ 57,190 61,656 8 35,317 35,957 –2

Missouri ......................................................................................... 12,248 12,320 1 8,174 9,012 –10

New Jersey ................................................................................... 32,663 22,228 –32 26,741 12,786 52

New York ...................................................................................... 19,889 20,853 5 16,930 14,644 14

North Carolina ............................................................................... 32,107 34,412 7 21,113 19,267 9

Ohio ............................................................................................... 50,946 53,329 5 32,799 30,923 6

Pennsylvania ................................................................................. 64,224 74,839 17 59,622 41,824 30

Rhode Island ................................................................................. 328 327 0 328 327 0

South Carolina .............................................................................. 34,791 34,994 1 20,097 18,671 7

Tennessee .................................................................................... 65,051 67,774 4 32,138 34,308 –7

Virginia .......................................................................................... 23,333 25,509 9 15,529 10,919 30

West Virginia ................................................................................. 41,510 42,733 3 31,377 21,066 33

Wisconsin ...................................................................................... 21,209 21,263 0 12,269 11,401 7

Total ....................................................................................... 698,233 722,101 3 466,158 399,416 14

TABLE III–6.—REVISED NOX BUDGET COMPONENTS AND PERCENT REDUCTION FOR NON-ELECTRICITY GENERATING

UNITS

[tons/season]

Revised base Revised

budget

Percent

reduction

Alabama ....................................................................................................................................... 48,187 24,416 49

Connecticut ................................................................................................................................... 5,254 3,103 41

Delaware ...................................................................................................................................... 5,276 2,271 57

District of Columbia ...................................................................................................................... 311 259 17

Georgia ......................................................................................................................................... 33,939 14,305 58

Illinois ............................................................................................................................................ 65,351 40,719 38

Indiana .......................................................................................................................................... 51,839 29,187 44

Kentucky ....................................................................................................................................... 19,019 11,996 37

Maryland ....................................................................................................................................... 10,710 5,852 45

Massachusetts .............................................................................................................................. 9,978 6,207 38

Michigan ....................................................................................................................................... 61,656 35,957 42
Federal Register / Vol. 63, No. 90 / Monday, May 11, 1998 / Proposed Rules 25909

TABLE III–6.—REVISED NOX BUDGET COMPONENTS AND PERCENT REDUCTION FOR NON-ELECTRICITY GENERATING

UNITS—Continued

[tons/season]

Revised base Revised

budget

Percent

reduction

Missouri ........................................................................................................................................ 12,320 9,012 27

New Jersey ................................................................................................................................... 22,228 12,786 42

New York ...................................................................................................................................... 20,853 14,644 30

North Carolina .............................................................................................................................. 34,412 19,267 44

Ohio .............................................................................................................................................. 53,329 30,923 42

Pennsylvania ................................................................................................................................ 74,839 41,824 44

Rhode Island ................................................................................................................................ 327 327 0

South Carolina .............................................................................................................................. 34,994 18,671 47

Tennessee .................................................................................................................................... 67,774 34,308 49

Virginia .......................................................................................................................................... 25,509 10,919 57

West Virginia ................................................................................................................................ 42,733 21,066 51

Wisconsin ..................................................................................................................................... 21,263 11,401 46

Total ...................................................................................................................................... 722,101 399,416 45

d. Options for Calculating the

Budgets. In the November 7, 1997 NPR,

EPA proposed budgets and developed

cost effectiveness data for non-utility

boilers and gas turbines together with

other non-utility point sources. The

budgets for these sources were based on

the applicable OTAG recommendation

of 70 percent reduction from

uncontrolled levels at large units

(greater than 250 mmBtu/hr), RACT at

medium units (other sources greater

than 1 ton per day) and no controls

beyond the baseline for small sources.

The revised budgets described in

Section III.A.2, Non-Electricity

Generating Point Sources, of today’s

action are based on the same approach.

Costs were estimated for these sources

using a least cost approach for each

State budget which assumed

incremental emissions reductions at the

most cost-effective sources in each

State, including small, medium, and

large units. In contrast, electric

generation sources were analyzed

separately using an emissions rate

approach to develop the budgets and the

Integrated Planning Model (IPM) was

run to estimate costs under an interstate

trading program. The November 7, 1997

NPR invited comment on the size

cutoffs used in the above analyses and

also specifically invited comment on

treating large combustion sources, such

as industrial boilers greater than 250

mmBtu (this level approximately

corresponds to greater than 1 ton per

day), at control levels equal to that for

large electric generation sources.

In today’s action, EPA is proposing to

include the non-utility boilers and gas

turbines greater than 250 mmBtu/hr

together with electric generation sources

as the core group of sources in the NOX

Budget Trading Program and analyze

both using IPM. As a result, EPA

intends to conduct additional analyses

as described below.

For the non-utility boilers and gas

turbines greater than 250 mmBtu/hr,

EPA intends to estimate costs using IPM

and assuming a trading program

involving these sources and the electric

generation sources. The emissions

budget would be calculated for these

sources the same as it was in the

November 7, 1997 NPR. The EPA also

solicits comments on whether to

calculate budgets for the non-utility

boilers and gas turbines through the

alternative means of an emission rate

basis (e.g., 0.20 lbs/mmBtu), similar to

the approach used by EPA for electric

generation sources in the November 7,

1997 NPR. The EPA invites comment on

these and other approaches for

calculating the budget component and

costs for the non-utility boilers and gas

turbines greater than 250 mmBtu/hr.

Additionally, EPA intends to further

analyze the point source categories that

are not part of the proposed core group

of sources in the NOX Budget Trading

Program (e.g., process heaters, stationary

internal combustion engines, and

cement manufacturing). These analyses

will look at applying (1) various costeffectiveness ceilings (e.g., maximum of

$2000 per ton); (2) percentage reduction

floors (e.g., minimum of 50 percent

reduction); and (3) combinations (e.g.,

$2000 per ton maximum and 50 percent

reduction minimum). These analyses

will cover individual source categories

not in the proposed core group of

sources of the NOX Budget Trading

Program as well as all such sources in

the aggregate. The EPA invites comment

on these and other approaches for

calculating the budget component and

costs for this group of sources.

In the November 7, 1997 NPR, EPA

noted that information on emissions and

potential control measures was

generally lacking for small sources. The

EPA believes that there are several

medium and large units for which such

information is also lacking. In the

November 7, 1997 NPR (and in the

revised budgets described in Section

III.A.2, Non-Electricity Generating Point

Sources), these units were assigned a 70

percent reduction target for large and

RACT for medium sized units,

consistent with the OTAG

recommendation. However, since EPA

cannot identify specific control

measures for these sources due to the

lack of available technical information,

EPA now proposes to keep them in the

statewide budgets at baseline levels,

without additional emission reductions.

As the above analyses are completed,

EPA intends to place them in the

docket.

3. Revised Statewide Budgets

The revised statewide budgets that

reflect the changes to the electricity

generating and non-electricity

generating point source sectors

described above are shown in Table III–

7.
25910 Federal Register / Vol. 63, No. 90 / Monday, May 11, 1998 / Proposed Rules

TABLE III–7.—REVISED STATEWIDE NOX BUDGETS

[tons/season]

State Base Budget Percent red.

Alabama ....................................................................................................................................... 241,564 155,617 36

Connecticut ................................................................................................................................... 52,014 39,909 23

Delaware ...................................................................................................................................... 30,568 21,010 31

District of Columbia ...................................................................................................................... 7,978 7,000 12

Georgia ......................................................................................................................................... 246,243 159,013 35

Illinois ............................................................................................................................................ 350,154 218,679 38

Indiana .......................................................................................................................................... 340,084 200,345 41

Kentucky ....................................................................................................................................... 263,855 158,360 40

Maryland ....................................................................................................................................... 118,065 73,628 38

Massachusetts .............................................................................................................................. 103,445 73,575 29

Michigan ....................................................................................................................................... 283,821 199,238 30

Missouri ........................................................................................................................................ 185,104 116,246 37

New Jersey ................................................................................................................................... 132,032 93,464 29

New York ...................................................................................................................................... 230,310 185,537 19

North Carolina .............................................................................................................................. 234,300 153,106 35

Ohio .............................................................................................................................................. 391,012 236,443 40

Pennsylvania ................................................................................................................................ 328,433 207,250 37

Rhode Island ................................................................................................................................ 12,175 10,132 17

South Carolina .............................................................................................................................. 169,572 109,267 36

Tennessee .................................................................................................................................... 291,225 187,250 36

Virginia .......................................................................................................................................... 219,835 162,375 26

West Virginia ................................................................................................................................ 158,240 81,701 48

Wisconsin ..................................................................................................................................... 142,759 95,902 33

Total .............................................................................................................................................. 4,532,790 2,945,046 35

B. Revised Cost Analyses

The EPA has revised the cost

estimates presented in the November 7,

1997 notice. As discussed in Section

III.A, Explanation of Revised Budgets,

additional emissions sources were

included in the emissions budgets and

several changes to the emissions

inventory were made. Also, revised unit

control cost estimates for Selective

Catalytic Reduction (SCR) and Selective

Non Catalytic Reduction (SNCR) were

prepared for non-electricity generating

point sources. The revised costs are now

more consistent with the way estimates

were developed for electricity

generating sources. Details on the

revised cost analysis are presented in

‘‘Supplemental Ozone Transport

Rulemaking Regulatory Analysis’’

(Supplemental Regulatory Analysis

TSD).

1. Electricity Generating Sources

The OTAG recognized the value of

market-based approaches to lowering

emissions from power plants and large

industrial sources. The Agency agrees

that a market-based approach with

trading is preferable as more cost

effective and encourages all States

covered by this rulemaking to establish

such a program. The Agency’s

regulatory analysis is based on this

view. As in the original proposal

analysis, analytical limitations kept EPA

from estimating the costs of a single capand-trade program for the electric power

industry and other large stationary

sources. In this SNPR, the analysis of a

cap-and-trade program, across all States

covered in the rulemaking, is limited to

sources in the electric power industry.

The analysis of the electric power

industry has been expanded to include

additional electricity-generating sources

(see Section III.A, Explanation of

Revised Budgets). Additionally, EPA

also updated many of the assumptions

included in the Integrated Planning

Model (IPM), including more recent

energy demand forecasts and more

recent information on future planned

new units. These changes are discussed

in the Supplemental Regulatory

Analysis TSD.

The EPA analyzed the cost of a NOX

cap-and-trade program with a summer

NOX emissions cap of 563,784 tons,

assuming reductions are effective by the

2003 ozone season. Annual cost

estimates are provided for 2003 and

2007.

2. Non-Electricity Generating Point

Sources

The costs for non-electricity

generating point sources are estimated

using two alternative approaches. The

first approach, called the Least Cost

Scenario, attempts to identify the mix of

sources and control technologies that

achieve each State’s non-electricity

generating budget level for point sources

at the lowest possible control cost. The

sources controlled under the Least Cost

Scenario may not be the same sources

that are controlled for the purpose of

establishing each State’s emissions

budget. The results of the Least Cost

Scenario are a proxy for State-level

emissions trading programs free of

transactions costs. If it were possible to

consider transactions costs, the Least

Cost Scenario would result in higher

cost estimates than are presented here.

On the other hand, if the Least Cost

Scenario had been modeled assuming

the States participate collectively in a

trading program for non-electricity

generating sources (i.e., domain-wide

trading as modeled in the electricity

generating sector), the resulting cost

estimates would likely be lower than

presented here.

The second approach, termed the

Command-and-Control Scenario,

attempts to estimate the cost of

controlling just those sources that were

used to establish each State’s emissions

budget. This method does not take into

account possible cost savings that can

be realized by more efficient regulatory

schemes, such as emissions trading, and

therefore tends to overstate the cost of

meeting the non-electricity generating

point source emissions budget.

The EPA has revised the cost of

controls associated with non-electricity

generating sources based on information

previously developed for the revised

IPM for electricity generating sources.

The new method for estimating SCR and

SNCR costs for non-electricity

generating sources is now more
Federal Register / Vol. 63, No. 90 / Monday, May 11, 1998 / Proposed Rules 25911

consistent with the estimates for

electricity generating sources. The

annual costs for non-electricity

generating sources are estimated based

on the 2007 non-electricity generating

source emissions projections. Unlike the

IPM analysis for electricity generating

sources, the cost analysis framework for

non-electricity generating sources did

not allow distinctions to be made

between the estimated annual cost of

compliance in 2003 relative to the year

2007. As shown in Section III.B.3, Cost

Analysis Results, the electricity

generating sector annual cost estimates

vary only 5 percent between 2003 and

2007. It is reasonable to believe that

non-electricity generating sector annual

cost would also not vary significantly

between 2003 and 2007.

For NOX point sources, EPA estimated

annual compliance costs for achieving a

total summer NOX emissions budget of

416,619 tons. This budget is slightly

higher (4 percent) than the 399,416 ton

budget presented in Section III.A.2,

Non-Electric Generation Point Sources,

because the cost analysis for nonelectricity generating point sources was

completed before all adjustments to the

proposed budgets had been finalized. If

the final 399,416 ton budget had been

analyzed the cost estimates for nonelectricity generating point sources

would have been only slightly higher.

3. Cost Analysis Results

Tables III–8 and III–9 show the

analysis results based on the changes to

the proposed emissions budgets and

cost methodology improvements. Table

III–8 shows the population of sources

covered by each element of the cost

analysis and the resulting NOX

emissions levels. Table III–9 shows the

estimated annual compliance costs and

average cost effectiveness.

TABLE III–8.—POPULATION OF EMISSIONS SOURCES AND NOX EMISSIONS AFTER COMPLIANCE WITH THE OZONE

TRANSPORT RULEMAKING

Budget component Number of

sources*

Ozone season

emissions

(1,000 NOX tons)

Electricity generating sources ...................................................................................................................... 1,757 564

Non-Electricity generating sources: Least Cost—2007 ............................................................................... 13,373 409

Non-Electricity generating sources: Command-and-Control-2007 .............................................................. 1,774 394

* The number of electricity generating sources reflects the number of sources in 1996 that were used to establish the summer season NOX

budget. The number of non-electricity generating sources reflects sources controlled for the purpose of estimating costs.

TABLE III–9.—INCREMENTAL ANNUAL CONTROL COSTS AND AVERAGE COST EFFECTIVENESS FOR COMPLIANCE WITH THE

OZONE TRANSPORT RULEMAKING

Budget component

Annual control

cost

(million 1990 dollars)

Average ozone

season cost effectiveness

($/ton)

Average annual

cost effectiveness

($/ton)

Electricity generating sources—2003 ......................................................................... 1,308 1,455 1,161

Electricity generating sources—2007 ......................................................................... 1,378 1,469 1,165

Non-Electricity generating sources: Least Cost—2007 ............................................. 456 1,500 640

Non-Electricity generating Sources: Command-and-Control—2007 ......................... 1,170 3,700 2,600

Based on the Least Cost Scenario for

non-electricity generating sources, the

incremental annual cost of the proposed

SIP call in 2007 for both electricity and

non-electricity generating sources is

$1.8 billion (1990 dollars).

IV. SIP Criteria and Emissions

Inventory Reporting Requirements

A. SIP Criteria

1. Introduction

The November 7, 1997 NPR explained

that each State would be required to

submit a SIP demonstrating ‘‘that each

State will meet the assigned statewide

emission budget’’ (62 FR 60365). It

further explained that each ‘‘SIP

revision should include the following

general elements related to the regional

strategy: (1) Baseline 2007 statewide

NOX emissions inventory (which

includes growth and existing control

requirements)—this would generally be

the emissions inventory that was used

to calculate the required statewide

budget; (2) a list and description of

control measures to meet [the] statewide

budget; (3) fully-adopted State rules for

the regional transport strategy with

compliance dates providing for control

between September 2002 and September

2004, depending on the date EPA adopts

in its final rulemaking; (4) clearly

documented growth factors and control

assumptions; and (5) a 2007 projected

inventory that demonstrates that the

State measures along with national

measures will achieve the State budget

in 2007.’’ Id.

The purpose of this Section is to

identify criteria for determining

completeness and approvability of a

State submittal in response to the final

SIP call. The criteria are set forth in

proposed regulatory language (40 CFR

51.121). In addition, this section

describes the actions the Agency

intends to take if a State fails to make

a submittal, or the Agency makes a

finding of incompleteness or

disapproves the SIP.

2. Completeness Determination

Any submittal that is made with

respect to the final SIP call first will be

determined to be either incomplete or

complete. A finding of completeness

means that EPA will review the

submittal to determine whether it is

approvable. It is not a determination

that the submittal is approvable; rather,

it means the submittal is

administratively and technically

sufficient for EPA to determine whether

it meets the statutory and regulatory

requirements for approval. In order for

any submittal to be complete, 40 CFR

51.121 provides that the submittal must

meet the criteria described in 40 CFR,

part 51, Appendix V, ‘‘Criteria for

Determining the Completeness of Plan

Submissions.’’ These criteria apply

generally to SIP submissions and so

should be familiar to States submitting

transport SIPs.

Section 1.2 of Appendix V, in

accordance with section 110(k)(1) of the
25912 Federal Register / Vol. 63, No. 90 / Monday, May 11, 1998 / Proposed Rules

2A more detailed discussion of sanctions and

FIPs appeared in the November 7, 1997 NPR at page

60368–69.

3NOX sources serving electric generators with a

nameplate capacity greater than 25 MWe and

boilers with a maximum design heat input greater

than 250 mmBtu/hr.

CAA, requires EPA to notify States

within 60 days of EPA’s receipt of a

submittal, but no later than 6 months

after the submittal is due. If a

completeness determination is not made

within 6 months after submission, the

submittal is deemed complete by

operation of law. For purposes of rules

submitted in response to the SIP call,

EPA intends to make completeness

determinations expeditiously. In

addition, EPA expects to make findings

of failure to submit no later than the

Agency makes completeness

determinations.

A finding of failure to submit or

incompleteness triggers an 18-month

sanctions clock that can only be stopped

by an affirmative EPA finding that the

State has made a complete submittal.

The findings also trigger the

requirement that EPA promulgate a

Federal implementation plan (FIP)

within 2 years of the date of the finding,

if the deficiency has not yet been

corrected. The EPA intends to propose

FIPs in the fall of 1998 and move

quickly to promulgate a FIP where

necessary. In addition, sanctions and

FIP clocks are triggered if a State

submits a complete SIP, but EPA

subsequently disapproves it, in whole or

in part.2

3. Approvability Criteria

In the November 7, 1997 NPR, EPA

highlighted several general elements

that must be included in ozone

transport SIP revisions. Without these

general elements, a SIP submission will

not be approved. This Section (1)

identifies EPA’s proposed additional

approvability criteria for control

strategies that will help States meet

their NOX budgets; and (2) provides

guidance to assist States in preparing

emissions inventories for purposes of

identifying emissions benefits of

possible control strategies. The existing

guidance documents listed below will

help States incorporate existing EPA

guidance into their SIPs. Much of the

pertinent guidance is available

electronically.

Each State must start with a baseline

2007 statewide NOX emissions

inventory, including growth and

existing control requirements. The 2007

projected control inventory must

demonstrate that the State measures,

along with national measures, will

achieve the State budget in 2007. The

EPA has issued documents to assist

States in developing emissions

inventories. Specifically, these

documents describe how to clearly

define the particular control measures

and document the methods used to

estimate emissions reductions from

implementation measures. A State need

not define these measures in its SIP to

the extent it chooses to achieve the

required reductions through the model

rule for the NOX Budget Trading

Program, which is being proposed in

this notice.

a. Additional Control Strategy

Approvability Criteria.

i. Introduction. The approvability

criteria for transport SIP submissions

appear in proposed 40 CFR 51.121. Most

of the criteria are substantially identical

to those that already apply to attainment

SIPs. For example, each submission

must describe the control measures that

the State intends to employ, identify the

enforcement methods for monitoring

compliance and handling violations,

and demonstrate that the State has legal

authority to carry out its plan. This part

of the preamble focuses on

approvability criteria that are being

proposed for the first time to ensure

States meet their NOX budgets.

ii. General Recommendations. As

discussed in the NPR (62 FR 60365–66),

regulatory requirements that employ a

maximum mass emissions limitation for

a source or group of sources provide the

greatest certainty that a specific level of

emissions will be attained and

maintained. With respect to transport of

pollution, a mass emissions limitation

also provides the greatest assurance to

downwind States that air emissions

from upwind States will be effectively

managed over time. Regulatory

requirements designed and enforced as

an emissions rate limitation can achieve

a measurable emissions reduction, but

the targeted level of emissions may or

may not be reached depending on the

actual activity level of the affected

source(s). Finally, regulatory

requirements designed as a specific

technology or measure have the greatest

uncertainty for achieving a targeted

emissions level due to uncertainty in

both the activity level of the affected

source(s) and uncertainty in the

effectiveness of the technology or

measure.

Based on the desire to establish

regulatory requirements with the

greatest likelihood of achieving and

maintaining the statewide NOX

emissions budget, EPA recommends

that, to the maximum extent practicable,

all regulatory requirements be in the

form of a maximum level of emissions

for a source or group of sources. The

EPA recognizes that this option may be

difficult for some sources because the

available emissions control options may

be limited, and the techniques for

quantifying mass emissions to ensure

compliance with a tonnage budget may

not be adequate.

iii. New Proposed Approval Criteria.

While mass emissions limitations may

be difficult for some sources, EPA

believes that, if the State chooses to

meet the budget through control

requirements for electric generators and

large industrial boilers, the State can

feasibly require these sources to

quantify mass emissions through

reasonably available measurement

technology. For this reason, as well as

others discussed below, EPA proposes

the following additional SIP

approvability criteria which would

apply if the State selected regulatory

requirements covering NOX sources

serving electric generators with a

nameplate capacity greater than 25

MWe and boilers with a maximum

design heat input greater than 250

mmBtu/hr:

• Regulatory requirements to meet the

2007 budget for these sources would

need to be expressed 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 sources’ 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 equivalent

or greater assurance than options (1) or

(2) that seasonal emissions budgets will

be attained and maintained.

• Sources would be required to

demonstrate that they have met these

applicable emissions control provisions

using continuous emissions monitors.

Further, EPA is taking comment on

whether sources should be required to

demonstrate that they met these

requirements using the monitoring

provisions of the Acid Rain Program for

monitoring NOX mass emissions in 40

CFR part 75.

The EPA believes control approaches

and monitoring for this group 3 of

sources have advanced to the point that

complying with, tracking, and enforcing

a maximum mass emissions limitation

or tonnage budget is reasonable. A

variety of regulatory programs are

currently in use or under development

that utilize a mass emissions limitation

for large combustion devices. These
Federal Register / Vol. 63, No. 90 / Monday, May 11, 1998 / Proposed Rules 25913

4See Memorandum from Kevin Culligan, EPA,

Acid Rain Division, to Docket regarding ‘‘Transport

SIP Call: Potential Continuous Emissions

Monitoring Systems Requirements’’ April 8, 1998,

Docket Number A–96–56, IV–B–01.

5Authority for the proposed additional SIP

approval criteria described above resides in sections

110(a) and 301(a) of the Clean Air Act. Specifically,

the requirement in section 110(a)(2)(A) that SIPs

include enforceable emissions limitations and other

control measures ‘‘as may be necessary or

appropriate’’ to meet the Clean Air Act, together

with the requirement in section 110(a)(2)(D) that

SIPs include ‘‘adequate provisions’’ to mitigate

certain transport effects on other States, implicitly

authorize EPA to impose the additional SIP

approval criteria described above to ensure that

affected States adequately mitigate their

contribution to ozone transport, given the reasons

and circumstances described above. Additionally,

section 301(a) grants EPA broad authority to

prescribe such regulations as are necessary to carry

out its functions under the Clean Air Act. The

proposed additional SIP approval criteria are

necessary for EPA to meet its obligation to approve

only SIPs that contain ‘‘necessary or appropriate’’

and ‘‘adequate’’ provisions for the applicable State

to mitigate its contribution to ozone transport.

regulatory systems include the EPA’s

Acid Rain Program for sulfur dioxide

(SO2) emissions, the South Coast Air

Quality Management District’s Regional

Clean Air Incentives Market for SO2 and

NOX, and the Ozone Transport

Commission’s NOX Budget Program.

Experience with these regulatory

programs indicates that establishing a

tonnage budget for large combustion

sources is currently feasible and cost

effective. These approaches exist

because there is a range of reasonable

options available for controlling

emissions from these sources. In

general, large combustion sources have

several effective control options for

reducing NOX emissions, including

combustion modifications, postcombustion technologies, and fuel

switching. This range of options

provides flexibility for these sources or

groups of sources to maintain a tonnage

budget for emissions.

For measuring emissions, continuous

emissions monitors, currently installed

at most sources participating in these

programs, provide accurate, complete

and timely accounting of emissions

which enable the administrators of these

programs to easily track and enforce

emissions on a mass emissions basis.

Therefore, EPA proposes that all of the

sources in this group must employ

continuous emissions monitoring.

Further, EPA seeks comment on what

specifications, if any, to require for such

continuous emissions monitoring

systems (CEMS). More specifically, EPA

is taking comment on requiring these

sources to meet the NOX mass emissions

monitoring and reporting provisions

that are contained in a proposed new

subpart to the monitoring and reporting

provisions of the acid rain regulations in

40 CFR part 75. These revisions are

being proposed in a separate notice

entitled ‘‘Acid Rain Program;

Continuous Emission Monitoring

Revisions’’ that will be published in the

Federal Register in the near future.

Electric utility units have been meeting

the current 40 CFR part 75 requirements

since at least 1995. The EPA believes

that the proposed 40 CFR part 75

provisions will provide accurate

monitoring of NOX mass emissions and

also provide flexibility, particularly for

smaller and infrequently operated

sources. Additional information on the

proposed 40 CFR part 75 requirements

can be found in Section V.C.9.a,

Requirements for Point Sources. Also,

EPA has prepared a memorandum for

the docket that compares the proposed

provisions of 40 CFR part 75 to other

available CEMS requirements.4

Another reason that States choosing to

control electricity generating sources

should use available means to assure

that the source’s mass emissions stay

within the State’s projected levels is that

recent changes in the utility industry

may foster substantial shifts in

electricity production from State to

State for market reasons. Given the

changing market forces in the electricity

generating industry today, State

measures to limit electricity generating

unit emission rates without accounting

for potential utilization increases would

provide little assurance that mass

emissions from these sources would be

reduced to the levels necessary to meet

the proposed budgets. For this reason,

too, EPA believes that regulatory

requirements for large combustion

sources to meet a State’s NOX budget

can and should be expressed and

enforced as mass emissions limitations

or an alternative providing equivalent

assurance that the mass reductions will

occur.

Finally, while EPA has not heretofore

imposed the proposed approvability

criteria on State ozone control measures,

EPA believes they are reasonable (as

described above) and appropriate in the

context of this transport rulemaking.

This SIP call addresses the regional

problem of emissions transport—i.e., the

problem of one State’s effect on one or

more other States. The EPA believes it

is appropriate to take reasonable and

feasible steps to minimize the potential

‘‘commons’’ phenomenon inherent in

this problem. Under the theory of the

commons, a State has less interest in

controlling pollution that is produced

within its borders but primarily affects

the health of non-residents, compared to

its interest in controlling pollution that

has intrastate effects. The additional

approvability criteria proposed today

offer downwind States the assurance

that upwind States, to the extent they

elect to control the applicable group of

sources, will implement measures that

offer transparent certainty of success.

Given the availability of reasonable

measures to control the applicable

group of sources in this way, and the

potential for substantial shifts in

utilization in the utility sector in

coming years, EPA believes it is

appropriate for this transport SIP call to

propose additional SIP approvability

criteria to address the potential

commons phenomenon.5

To assist States with the development

and implementation of an emissions

budget for large combustion sources,

EPA is proposing the NOX Budget

Trading Program in section V of today’s

notice. States may voluntarily choose to

participate in the NOX Budget Trading

Program by adopting the model rule.

This multistate trading program would

provide sources the flexibility and cost

effectiveness of a market based system,

while meeting the additional SIP

approvability criteria for States that are

proposed in this section.

The EPA intends 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 reductions to be

expected from the State’s adoption of

the model rule. As noted above, today’s

action proposes that transport SIP

submissions comply with various

approval criteria that are substantially

identical to existing approval criteria for

attainment SIPs. Those criteria include:

(1) A demonstration by the State that it

has the legal authority to adopt and

implement each of the control measures

contained in the SIP submission, and (2)

a demonstration of the expected

emissions reductions to be achieved

from each new control measure.

Provided a State meets these two criteria

with respect to its adoption of the model

rule, then EPA intends to approve the

model rule portion of the State’s SIP

submission.

A State or group of States may also

choose to develop, adopt, and

implement their own cap-and-trade

program separate from today’s proposed

NOX Budget Trading Program. In

developing these alternative programs,
25914 Federal Register / Vol. 63, No. 90 / Monday, May 11, 1998 / Proposed Rules

States should follow the available

guidance in the Economic Incentive

Program requirements (see 40 CFR part

51, subpart U) and EPA’s Emissions

Trading Policy Statement (see 51 FR

43814, December 4, 1986) in addition to

the transport SIP approval criteria in

proposed 40 CFR 51.121.

Regulatory requirements used to meet

the 2007 budget for other sources not

identified in the above description may

be expressed as (1) a mass emissions

limit, (2) an emissions rate, or (3)

specific technology or measure. As

discussed above, EPA recognizes that it

may not be reasonable to require

regulatory requirements to be expressed

as mass emissions limitations for all of

these sources because of limitations

with control options and the ability to

measure mass emissions. Moreover,

EPA believes that the likelihood of

substantial shifts in demand (and

corresponding changes in emissions

compared to historical actuals) is lower

for these other sources. Therefore, EPA

believes there is substantially less risk

with respect to these sources that past

representative production rates will

prove unreliable predictors of future

activity. However, EPA recommends

that mass emissions budgets also be

used for these sources to the maximum

extent practicable.

The EPA solicits comments on the

proposed SIP approvability criteria for

regulatory requirements that govern

emissions from large combustion

sources. In addition, EPA solicits

comments as to the reasonableness of

expressing regulatory requirements as

mass emissions limitations for other

sources.

b. Emissions Inventory Preparation

Guidance and Control Strategies

Guidance. This Section presents

guidance that States should follow

when initiating the planning and

development of an emissions inventory.

The documents referenced below

describe control measures a State may

wish to consider for purposes of

meeting a statewide NOX budget. Most

of these documents can be obtained

directly by computer download from the

EPA’s Clearinghouse for Inventories and

Emission Factors (CHIEF) Web Site

(http://www.epa.gov/ttn/chief) or by

contacting the InfoCHIEF helpline at

(919) 541–5285.

Descriptions of a number of potential

data sources that can be consulted for

emission estimation methods are

provided below. Site-specific source

tests are generally expected to provide

a better estimate for the tested site than

average emission factors (including

factors cited in ‘‘Compilation of Air

Pollutant Emission Factors (AP–42)’’)

derived from testing at similar sources.

Site-specific tests should be based on a

reliable test procedure and should

represent typical operating conditions at

the site before being assumed to be

superior to an average emission factor.

The CEMS data for a given site can be

considered a superior form of sitespecific source test data. Material

balances for NOX sources, and

particularly combustion NOX sources,

are not appropriate and should not be

used.

If reliable site-specific tests or

calculation methods are not available or

are not feasible to use for all sources, an

emission factor or emission model

approach can be used. The EPA’s Factor

Information Retrieval (FIRE) Data

System provides a searchable electronic

listing of all criteria, toxic, and

greenhouse gas emission factors

appearing through the latest printed

AP–42 supplement for stationary

sources. The FIRE database also

contains a number of non-AP–42

factors, but only for sources where no

AP–42 factor exists. In addition, FIRE

contains a reference indicating if the

factor is from AP–42 or another source,

and it contains the factor quality rating

if one exists. Note that mobile source

emission factors do not appear in FIRE.

The most recently finished AP–42

stationary source revisions can only be

found on the CHIEF web site (http://

www.epa.gov/ttn/chief/ap42etc.html).

If an emission factor is not available

from one of the above sources, or if the

inventory preparer wants to improve the

emissions estimates for sources deemed

significant, the following data sources

may be of use.

• ‘‘Volume I, Introduction to the

Emission Inventory Improvement

Program (EIIP)’’ (EPA–454/R–97–

004a)—

http://www.epa.gov/ttn/chief/eiip/

techrep.htm#intro

• ‘‘Volume II, Preferred and

Alternative Methods for Estimating Air

Emissions from Point Sources’’ (EPA–

454/R–97–004b)—

http://www.epa.gov/ttn/chief/eiip/

techrep.htm#pointsrc

• ‘‘Volume III, Preferred and

Alternative Methods for Estimating Air

Emissions from Area Sources’’ (EPA–

454/R–97–004c)—

http://www.epa.gov/ttn/chief/eiip/

techrep.htm#areasrc

• ‘‘Volume IV, Preferred and

Alternative Methods for Estimating Air

Emissions from Mobile Sources’’ (EPA–

454/R–97–004d)—

http://www.epa.gov/ttn/chief/eiip/

techrep.htm#mobsrc

• ‘‘Procedures for the Preparation of

Emission Inventories for Carbon

Monoxide and Precursors of Ozone,

Volume I: General Guidance for

Stationary Sources’’ (EPA–450/4–91–

016)—

This document provides general

procedures for estimating emissions

from point and area stationary sources;

it may still be useful for estimating

emissions from area sources that are not

yet covered in the EIIP area source

guidance document (e.g., small publicly

owned treatment works, aircraft

refueling, on-site incineration,

residential heating (excluding wood

fuel), barge and tank drum cleaning). It

is not available in electronic form. Paper

copies are available from the InfoCHIEF

help desk (919) 541–5285.

• ‘‘Procedures for the Preparation of

Emission Inventories for Carbon

Monoxide and Precursors of Ozone,

Volume II: Emission Inventory

Requirements for Photochemical Air

Quality Simulation Models’’ (Revised)

(EPA–450/R–92–026)—

This document offers technical

assistance to those engaged in the

planning and development of detailed

emissions inventories for use in

photochemical air quality simulation

models. It includes guidance for

identifying and incorporating the

additional detail required by

photochemical air quality simulation

models into an existing base year

inventory. It is not available in

electronic form. Paper copies are

available from the InfoCHIEF help desk

(919) 541–5285.

• ‘‘Procedures for Emission Inventory

Preparation, Vol. IV: Mobile Sources’’

(EPA–450/4–81–026d [Revised]) (You

can download a zipped WordPerfect file

of this document from the ‘‘Emission

Inventory Guidance’’ Section of the

CHIEF Web Site.)

http://www.epa.gov/ttn/chief/

eilguide.html

c. Growth estimates. In order for EPA

to approve a SIP for the proposed Ozone

Transport Rule, the State must clearly

document growth factors and control

assumptions used in the budget

calculations. To the extent the State

uses EPA growth factors and control

assumptions, the SIP need only include

a statement attesting to this. If a State

wants to substitute its own growth

factors or control assumptions in the

budget analysis, it must provide

adequate justification for using the

alternative numbers. As stated in the

November 7, 1997 NPR (62 FR 60367),

EPA believes it is important that

consistent emissions growth estimates

be used for the State’s budget
Federal Register / Vol. 63, No. 90 / Monday, May 11, 1998 / Proposed Rules 25915

6The EPA is not now seeking comment on the

optional alternative approach of an offset pool. The

approach is described here solely for the purpose

of informing States of the potential for such an

approach and its potential relationship to the

growth estimates in the SIP call rulemaking. If EPA

pursues this approach, the agency will propose it

for comment in a separate Federal Register notice

and intends to take final action by the end of this

year. In particular, to the extent that the offset pool

option might elaborate upon or vary from existing

Agency policy or guidance, such differences will be

addressed in the later notice.

7 In this discussion of reporting requirements,

September 2002 is presumed to be the compliance

date for NOX transport call controls. As discussed

earlier, the final rule may adopt a different date for

compliance which may, in turn, affect the dates in

the final requirements for State reporting.

demonstration and for EPA’s calculation

of the required statewide emissions

budget. The EPA will evaluate any

revision to these growth factors or

control assumptions that is suggested

during the comment period on this rule

and may recalculate the required

statewide budget to reflect the State’s

change. Because the revised growth

estimates will be included in EPA’s

budget calculation, lower growth rates

could not be considered part of a State’s

NOX control strategy to attain that

budget unless the change in growth is

the result of clearly identified control

strategies that can be shown to provide

real, permanent, and quantifiable

changes in growth. In the November 7,

1997 NPR, EPA encouraged States to

request any changes to growth estimates

or control assumptions during the

comment period for the proposal so that

budgets given in the final rulemaking

would reflect these changes. Guidance

on how to prepare emission growth and

projections is listed below.

The EPA is currently considering an

optional alternative approach for States

to use to meet the major source offset

requirements under section 173 of the

Act (new source review (NSR) for

nonattainment areas).6 This approach

would allow States to create an offset

‘‘pool’’ composed of actual emissions

reductions that generally will be

achieved as a result of NOX control

strategies adopted in response to the SIP

call. To create an offset pool, at the time

States revise their SIPs to include

statewide NOX control measures, under

certain conditions states could set aside

a subset of their emissions reductions

generated from those measures for the

purpose of offsetting anticipated

emissions increases of ozone precursors

from new and modified major sources

that would be subject to nonattainment

NSR preconstruction permitting. (The

EPA is considering modifying the NSR

regulations to consider both NOX and

VOC ozone precursors in all areas.

Under such an approach, for offset

purposes, VOC emissions increases from

new and modified major sources could

be offset with NOX emissions decreases

where appropriate.)

The EPA currently anticipates that

those States subject to the NOX SIP call

will be able to take advantage of the

offset pool idea, as compliance with the

SIP call will necessitate emissions

reductions that are likely to be

creditable as offsets. Specifically,

because States’ budgets under the SIP

call account for a certain increment of

new major source growth, states may set

aside that increment in an offset pool

and still comply with the budgets

mandated by the SIP call. Thus, to take

full advantage of the offset pool

approach, States would need to ensure

that they have projected sufficient

growth considering major new sources

and major modifications to existing

major sources that will be locating in

existing and new nonattainment areas.

In general, EPA believes that sufficient

growth assumptions have been built

into the budget calculations to allow an

adequate margin for new source offsets.

Nevertheless, before EPA finalizes the

NOX budgets, States have an

opportunity to reevaluate and adjust

growth factors and control assumptions

to ensure that the final budgets

accurately reflect State-specific forecasts

of major new source growth.

Consequently, EPA recommends that

States covered by this rulemaking and

interested in using offset pools review

their emissions growth assumptions and

projections for anticipated new and

modified major sources that will

become part of their 2007 baseline

emissions inventories under this

rulemaking to ensure that growth

projections accurately reflect the

expected new emissions that will be

required to be offset under major NSR.

d. Emissions Growth Projection

Guidance.

• ‘‘Procedures for Preparing

Emissions Projections’’ EPA–450/4–91–

019, July 1991 (Hard copy only

available).

• ‘‘Guidance for Growth factors,

Projections, and Control Strategies for

the 15 Percent Rate-Of-Progress Plans’’

EPA 452/R–93–002, March 1993 (Hard

copy only available).

B. Emissions Reporting Requirements

for States

As stated in the November 7, 1997

NPR, 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 budget and to

assure the downwind affected States

and EPA that the ozone transport

problem is being mitigated. Emissions

reporting requirements for States subject

to this SIP call are discussed in this

Section.

1. Use of Inventory Data

If tracking and periodic reports

indicate that a State is not implementing

all of its NOX control measures

beginning in September 2002 7 or is off

track to meet its statewide budget by

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. As described more

fully in the NPR (62 FR 60364—60369),

noncompliance with the NOX transport

SIP 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. If emissions exceed the required

budget in any year after 2006, the

control strategies in the SIP will need to

be strengthened. The EPA will evaluate

the circumstances for the budget failure

and may issue a call for States to revise

their SIPs, as appropriate.

2. Legal Authority

The legal authority for the proposed

State reporting requirements described

in this Section resides in sections 110(a)

and 301(a) of the Clean Air Act.

Specifically, the requirement in section

110(a)(2)(D) that SIPs include ‘‘adequate

provisions’’ to mitigate certain transport

effects on other States implicitly

authorizes emissions inventory

reporting to EPA, as reporting will be

needed and appropriate to verify that a

State is in fact meeting its NOX budget.

Section 110(a)(2)(F) provides additional

authority for requiring that SIP call

submissions include provisions for

emissions reporting by sources to a

State, correlation of source information

by the State, and steps by the State to

make the correlated information

available to the public. Section

110(a)(2)(K), in turn, requires a State to

submit to EPA as requested, data related

to modeling the effect of NOX and other

emissions on ambient air quality. The

reported emissions inventory data

described in this Section will be used by

EPA in air quality modeling to assess

the effectiveness of the transport

rulemaking’s regional strategy. Finally,

section 301(a) grants EPA broad
25916 Federal Register / Vol. 63, No. 90 / Monday, May 11, 1998 / Proposed Rules

8 2003 would be the year for which the data

would be reported. The actual reporting schedule

is given in the Reporting Schedule Section.

9The EPA is proposing to define point source for

this rule as a non-mobile source which emits 100

tons or more per year of NOX emissions. Nonmobile sources which emit less than 100 tons per

year of NOX would be considered area sources. This

definition of point source is consistent with current

reporting requirements for NOX emissions.

authority to prescribe such regulations

as are necessary to carry out its

functions under the CAA. These

proposed regulations are necessary for

EPA to properly carry out its evaluation

of compliance with the SIP call.

3. Background for Reporting

Requirements

In the November 7, 1997 NPR, EPA

indicated that it intended to work with

affected States to determine what

reporting procedures are needed to

provide adequate assurance that the

emissions budgets are being achieved.

On January 13, 1998, EPA held a 1-day

workshop with the States to discuss

tracking issues. The objectives of the

workshop were to determine what type

and frequency of inventory reporting are

feasible for the different source sectors

(power generating sources, other point

sources, area sources, and mobile

sources) to identify key reporting issues

related to each sector, and to develop

recommendations on reporting

requirements to ensure compliance with

the SIP call. The goal was to share

information and ideas rather than to

reach consensus. A summary of the

meeting is contained in the docket

(docket number V–B–18) for this

rulemaking.

The workshop participants generally

thought that existing reporting

requirements for attainment SIPs should

be used whenever possible to minimize

any new reporting burden. The States

further recommended that the degree of

reporting rigor should be directly

related to the sectors that the State

chooses to control in its NOX transport

strategy. Reporting every 3 years was

considered feasible for all source

sectors. Reporting on an annual basis

was considered both achievable and

necessary for all source sectors that a

State chooses to regulate specifically for

the purpose of meeting the NOX budgets

proposed in the SIP call. This would

include all NOX sources within the State

which are subject to measures included

by the State in its transport SIP revision

in response to this SIP call. In addition,

it was noted that sources or source

categories that would be participating in

a trading program would need to meet

the reporting protocols specific to that

program. Consideration was also given

to establishing uniform monitoring and

reporting requirements and a

centralized data base for reporting for

other sources. Several States indicated

support for this concept if there were

easy access to the data by all parties. For

all source sectors, the States suggested

that emissions rather than indicators

should be reported.

4. Proposal

After taking into account the

suggestions on tracking of the

participants in the workshop, EPA today

is proposing inventory reporting

requirements for States subject to the

NOX SIP call. The regulatory text

appears in proposed § 51.122 and is

described below.

The EPA is proposing that States

report emissions annually starting with

data for the year 2003 8 for any

emissions source (point, area, or mobile)

to which additional controls are being

applied for the purpose of meeting the

NOX budget, with certain exceptions as

discussed below, and from any

emissions source that will either sell or

buy NOX emission allowances. The EPA

is also proposing that States develop

and submit comprehensive statewide

NOX inventories, including all NOX

sources, controlled and uncontrolled,

every 3 years, starting with data for the

year 2002.

The tracking requirements for meeting

the NOX SIP call budget attempt to make

use of existing inventory reporting

mechanisms as much as possible so that

existing requirements are not

duplicated. However, the reporting

requirements outlined below are more

comprehensive than current reporting

requirements for attainment SIPs in two

respects. This is because EPA proposes

that States report emissions from area

sources and mobile sources annually if

the State adopts new measures to reduce

emissions from these sources for

purposes of meeting the NOX budget.

Currently, there is no annual reporting

requirement for area or mobile sources.

In addition, States are not currently

required to report on a 3 year cycle

emissions from area and mobile sources

in attainment areas. States would be

required to report Statewide area and

mobile source ozone season emissions

every third year under the proposed

requirements.

Details of reporting for specific source

types are set forth below.

5. Annual Reporting

Annual NOX emissions reporting

requirements for point, area and mobile

source emissions are to start for the year

2003. The State must submit annual

reports for all sources the State chooses

to regulate specifically for the purpose

of meeting the NOX budgets proposed in

the SIP call. This would include all NOX

sources within the State which are

subject to measures included by the

State in its transport SIP revision in

response to this SIP call. For example,

a State would not have to submit an

annual report for NOX emissions for a

cement kiln which was controlled prior

to 1998 for RACT purposes. However, if

the State chose to go beyond RACT

requirements for the cement kiln in

order to meet its budget, the State would

have to report annually the emissions

for the source. Emissions inventory

reports are to be submitted according to

the Reporting Schedule Section below.

a. Point Sources.9 The EPA proposes

that States be required to report NOX

emissions annually for all point sources

that are subject to regulations

specifically for the purpose of meeting

the NOX budgets proposed in this SIP

call. The State must report emissions

from such point sources both for the

whole year and for the ozone season

(May 1 to September 30). The direct

reporting from sources to EPA of data

used for compliance with the

requirements of a trading program

meeting the requirements of 40 CFR Part

96 can be used to satisfy this

requirement. The EPA is also taking

comment on requiring electrical

generating units and large industrial

boilers to use the monitoring provisions

in 40 CFR Part 75 to account for their

emissions. This topic is more

thoroughly discussed in Section IV.A.3,

Approvability Criteria.

b. Area Sources. The EPA proposes

that the State determine area source

NOX ozone season emissions for source

categories that are controlled beyond

otherwise applicable Federal, State or

local measures to meet the NOX budget

and report these annually to EPA. A

State need not report annually the

emissions from an area source sector if

the State does not require additional

NOX reductions from that sector in

order to meet the transport rule’s NOX

budget.

c. Mobile Sources. The EPA proposes

that a State determine statewide mobile

source NOX ozone season emissions and

report these to EPA annually if the State

is requiring additional controls for

purposes of meeting the NOX budget.

Reductions from Federal measures are

already assumed in the budget. A State

need not report annually the emissions

from mobile sources if the State does

not require additional NOX reductions

from that sector in order to meet the

transport rule’s NOX budget.
Federal Register / Vol. 63, No. 90 / Monday, May 11, 1998 / Proposed Rules 25917

10The actual submittal of data by the State would

only be required 12 months after the end of 2002.

The data should be submitted according to the

schedule in the Reporting Schedule Section.

6. Reporting Every Third Year (3-Year

Cycle or Triennial Reporting)

Consistent with current 3-year

reporting requirements, EPA proposes

that for every third year, starting in

2002, States would be required to

submit to EPA statewide NOX emissions

data from all NOX sources (point, area,

and mobile) within the State.10 These

data would include data from all source

categories in the State regardless of

whether those sources are being

controlled to meet the requirements of

the transport rulemaking. For triennial

reporting for area and mobile sources,

only ozone season emissions must be

reported. For triennial reporting for

point sources, both ozone season and

annual emissions must be reported.

7. 2007 Report

The EPA proposes that in 2007, States

submit to EPA statewide NOX emissions

data from all NOX sources (point, area,

and mobile) within the State. This

would include data from all source

categories in the State regardless of

whether those sources are being

controlled to meet the requirements of

the transport rulemaking. For the 2007

report, only ozone season emissions

must be reported for area and mobile

sources, while both ozone season and

annual emissions must be reported for

point sources. The data reporting

requirements are identical to the

reporting requirements for the 3-year

cycle inventories, and this reporting

requirement is being proposed to allow

evaluation of whether budget

requirements are met for 2007. This onetime 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 in consecutive

years, i.e., 2007 and 2008.

8. Ozone Season Reporting

The EPA is proposing that the States

provide ozone-season 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 area and mobile

sources, only ozone season data must be

reported for the annual, triennial, and

2007 inventories. For point sources, the

State must report emissions for the

whole year, as well as for the ozone

season, since States are already required

under other existing inventory

provisions to submit the data for the

whole year. For the annual report,

emissions need only be reported for

source categories that a State chooses to

regulate specifically for the purpose of

meeting the NOX budgets proposed in

the SIP call. This would include all NOX

sources within the State which are

subject to measures included by the

State in its transport SIP revision in

response to this SIP call. 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 proposing that each State

provide its ozone season calculation

method to EPA for approval.

9. 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. The EPA proposes that

States would be required to report

emissions data in an electronic format to

the location 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 a trading program

meeting the requirements of 40 CFR part

96 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. The EPA also

solicits comment on whether this option

should be expanded to additional

stationary sources.

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.

10. Reporting Schedule

The EPA is proposing 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 Regional

Office when making the submittals.

In a related rulemaking effort, EPA is

currently developing the consolidated

emissions inventory reporting rule.

Among other things, the rule will be

proposing that all States in the Nation

submit statewide inventories of ozone

precursors (NOX, VOC, CO) every 3

years beginning with 1999 data. The

third year reporting requirement for the

transport rule has been developed to be

consistent with that reporting cycle.

However, the proposed 2002 start date

for the transport rule emissions reports

is 3 years later than the start date for the

consolidated rule reports. The EPA is

considering an 18-month reporting

schedule for the latter rule. The EPA

expects that, as States gain experience

in developing statewide emissions

inventories, less time will be needed to

gather and quality assure the data. Once

States have completed the first cycle of

reporting for 1999 under the

consolidated rule, they may have

sufficient procedures in place to allow

for an accelerated reporting schedule.

Therefore, because of the importance of

the NOX inventory reports for

determining compliance with the NOX

budgets, EPA believes it is appropriate
25918 Federal Register / Vol. 63, No. 90 / Monday, May 11, 1998 / Proposed Rules

to require a 12-month reporting

schedule for the transport rulemaking.

The EPA recognizes that there are

different constraints on data collection

for the point, mobile, and area source

categories. Therefore, EPA is also

soliciting comment on whether different

reporting schedules should be

established for the different source

categories, such that data that can be

obtained more readily should be

submitted sooner. For example, because

point sources are already known to State

agencies, and their operating parameters

will not change significantly from year

to year, the time needed to collect and

quality assure data may be shorter than

for the other categories. The new data

submission procedures discussed above

may allow further reductions in the

reporting time. The EPA is soliciting

comment on whether the State reporting

time for point 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.

For mobile and area sources, the

necessary reporting time frames may be

longer than for point sources due to the

delay in obtaining activity data from

information sources outside the

inventory preparing agency. In many

cases, surveys to collect new activity

data are required by the inventory

preparing agency to be able to calculate

emissions estimates. As with point

sources, the new data submission

procedures may allow reductions in the

reporting time. The EPA is soliciting

comment on whether no later than 6 or

9 months after the end of the applicable

calendar year would be a feasible time

frame for submitting mobile and area

source emissions inventory reports.

If different reporting schedules are

established for the different source

categories in the final rule, the EPA is

proposing that, for the third year

complete statewide inventory, States

submit a summary report identifying the

separate submittals and totaling the

statewide NOX ozone season emissions

to demonstrate progress toward, and

ultimately compliance with, their NOX

budget.

11. Confidential Data

Emissions data being requested in

today’s proposal would not be

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.

12. Data Elements To Be Reported

In addition to reporting ozone season

NOX emissions, the State should 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.

V. NOX Budget Trading Program

In the November 7, 1997 proposed

rulemaking to reduce the transport of

ozone and facilitate attainment of the

NAAQS for ozone, EPA offered to

develop and administer a multistate

NOX trading program to assist States in

the achievement of these goals; today’s

notice proposes such a program. The

trading program being proposed

employs a cap on total emissions in

order to ensure that emissions

reductions under the proposed transport

rulemaking are achieved, while

providing the flexibility and cost

effectiveness of a market-based system.

This Section provides background

information and a description of the

NOX Budget Trading Program, as well as

an explanation of how the trading

program would interface with other

State and Federal programs. In addition,

a model rule for the trading program is

proposed. States can voluntarily choose

to participate in the NOX Budget

Trading Program by adopting the model

rule, which is a fully approvable control

strategy for achieving emissions

reductions required under the proposed

transport rulemaking.

Should the States voluntarily choose

to participate in the NOX Budget

Trading Program by adopting the model

rule, EPA’s authority to cooperate with

and assist the States in the

implementation of the trading program

resides in both State law and the CAA.

With respect to State law, any State

which elects to adopt the model rule as

part of its transport SIP will be

authorizing EPA to assist the State in

implementing the trading program with

respect to the sources in that State. With

respect to the CAA, EPA believes that

the Agency’s assistance to those States

that choose to participate in the trading

program will facilitate the

implementation of the program and

minimize any administrative burden on

the States. One purpose of title I of the

CAA is to offer assistance to States in

implementing title I air pollution

prevention and control programs (42

U.S.C. 101(b)(3)). In keeping with that

purpose, section 103(a) and (b) generally

authorize EPA to cooperate with and

assist State authorities in developing

and implementing pollution control

strategies, making specific note of

interstate problems and ozone transport.

Finally, section 301(a) grants EPA broad

authority to prescribe such regulations

as are necessary to carry out its

functions under the CAA. Taken

together, EPA believes that these

provisions of the Act authorize EPA to

cooperate with and assist the States in

implementing the NOX Budget Trading

Program in the ways set forth in the

model rule.

A. Program Summary

1. Purpose of the NOX Budget Trading

Program

The OTAG concluded that an

emissions trading program could

facilitate cost effective emissions

reductions from large combustion

sources (for more information on OTAG,

see Section V.B.1.). When designed and

implemented properly, a market-based

program offers many advantages over its

traditional command-and-control

counterpart. The OTAG articulated five

principal advantages of market-based

systems: (1) Reduced cost of

compliance; (2) creation of incentives

for early reductions; (3) creation of

incentives for emissions reductions

beyond those required by regulations;

(4) promotion of innovation; and (5)

increased flexibility without resorting to

waivers, exemptions and other forms of

administrative relief (OTAG 1997

Executive Report, pg. 57). These benefits

result primarily from the flexibility in

compliance options available to sources

and the monetary reward associated

with avoided emissions in a marketbased system. The cost of compliance in

a market-based program is reduced

because sources have the freedom to

pursue various compliance strategies,

such as switching fuels, installing

pollution control technologies, or

buying authorizations to emit from a

source that has over-complied. Since an

emission rate or emissions level below

the level mandated allows the

generation of credits or allowances that

may be sold on the market, pollution

prevention becomes more cost effective,

and innovations in less-polluting

alternatives and control equipment are

encouraged.

A market system that employs a fixed

tonnage limitation (or cap) for a source

or group of sources provides the greatest

certainty that a specific level of

emissions will be attained and

maintained since a predetermined level
Federal Register / Vol. 63, No. 90 / Monday, May 11, 1998 / Proposed Rules 25919

of reductions is ensured. With respect to

transport of pollution, an emissions cap

also provides the greatest assurance to

downwind States that emissions from

upwind States will be effectively

managed over time. The capping of total

emissions of pollutants over a region

and through time ensures achievement

of the environmental goal while

allowing economic growth through the

development of new sources or

increased use of existing sources. In an

uncapped system, (where, for example,

sources are required only to

demonstrate that they meet a given

emission rate), the addition of new

sources to the regulated sector or an

increase in activity at existing sources

can increase total emissions even

though the desired emission rate control

is in effect.

In the NOX Budget Trading Program,

EPA proposes to implement jointly with

participating States, a capped marketbased program for certain combustion

sources to achieve and maintain an

emissions budget consistent with the

proposed transport rulemaking. An

emissions cap or budget trading

program for large combustion sources is

a proven and cost-effective method for

achieving emissions reductions while

allowing regulated sources compliance

flexibility.

Although participation in the NOX

Budget Trading Program is

discretionary, EPA encourages States to

participate in the trading program as a

cost-effective way of meeting their

emissions reductions obligations under

the proposed transport rulemaking.

Specifically, today’s proposal is

designed to assist States in: (1)

Achieving, through a program covering

certain large stationary combustion

sources, emissions reductions required

under the proposed transport

rulemaking; (2) ensuring flexibility for

regulated sources; (3) reducing

compliance costs for sources; and (4)

reducing administrative costs to States.

Adoption of the NOX Budget Trading

Rule would ensure consistency in

certain key operational elements of the

program among participating States,

while allowing each State flexibility in

other important program elements.

Uniformity of the key operational

elements across the NOX Budget

Trading Program region is necessary to

ensure a viable and efficient trading

program with low transaction costs and

minimum administrative costs for

sources, States, and EPA.

The effect of NOX emissions on air

quality in down wind nonattainment

areas depends, in part on the distance

between sources and receptor areas.

Sources that are closer to the

nonattainment area tend to have much

larger effects on air quality than sources

that are far away. In light of this, and as

discussed in Section VII, the Agency

plans to evaluate alternative approaches

in developing the final rule.

The Agency solicits comments on

whether a trading program should factor

in differential effects of NOX emissions

in an attempt to strike a balance

between achieving the cost savings from

a broader geographic scope of trading

and avoiding the adverse effects on air

quality that could result if the

geographic domain for trading is

inappropriately large or trades across

areas are not appropriately adjusted to

reflect differential environmental

effects. The Agency could consider

establishing ‘‘exchange ratios’’ for tons

traded between areas. The large number

of areas in the region violating the

standards and the several different

weather patterns associated with

summertime ozone pollution episodes

complicate the development of a stable

set of trading ratios. Alternatively, the

Agency could consider establishing

subregions for trading within the 23-

jurisdiction area and apply a discount to

or prohibit trades between regions.

The Agency solicits comments on this

issue. If after review of alternative

approaches (including sub-regional

modeling analysis submitted by the

States and other commenters), EPA

concludes that an alternative approach

is appropriate, EPA will issue a SNPR.

2. Emissions Reductions Required by

the Proposed Transport Rulemaking

Each of the 22 States and the District

of Columbia, determined by EPA in the

proposed transport rule to make a

significant contribution to

nonattainment or interfere with

maintenance in another jurisdiction, has

been assigned a statewide NOX

emissions budget. Each of these States

must submit a SIP revision delineating

the controls that will be implemented to

meet its specified budget. Each State has

complete discretion to develop and

adopt a mix of control measures

appropriate for meeting its assigned

emissions budget. Today’s proposal

assumes that compliance with the

emissions reductions requirements for

the transport rulemaking will begin on

May 1, 2003, as proposed in the

transport rulemaking. If a different

compliance deadline is required in the

final transport rulemaking, the

deadlines in the proposed trading rule

will be adjusted accordingly.

In the proposed transport rulemaking,

EPA calculated seasonal NOX emissions

budgets for States, assuming activity

growth levels through 2007 and the

application of reasonable, cost-effective

controls that are currently available to

achieve NOX reductions. The statewide

budgets were developed by applying

appropriate controls to each sector of

the total State emissions inventory: large

electricity generating devices, point

sources other than large electricity

generators, nonroad engines, highway

vehicles, and area sources. The

statewide NOX budget development

process is fully described in Section

III.B. of the November 7, 1997 proposal

(62 FR 60346).

As outlined in the proposed transport

rulemaking, budget levels calculated for

nonroad engine, highway vehicle, and

area source inventory sectors assume

continued application of controls

already required for those source sectors

in addition to implementation of

Federal measures, such as the National

Low Emissions Vehicle Program. The

statewide seasonal NOX budgets

proposed for the large electricity

generating source sector (fossil-fuel

burning electricity utility units and

nonutility units serving electricity

generators greater than 25 MWe) were

based on applying a uniform NOX

emission rate of 0.15 lb/mmBtu to

projected generating activity levels.

Budget estimates for States’ nonutility

point source sector were developed

assuming a 70 percent reduction from

future emissions levels of large sources

(greater than 250 mmBtu/hour), and

application of RACT to medium sized

sources (100–250 mmBtu/hour) in this

category.

Though States are free to

independently determine their control

strategies to achieve their statewide

budgets, several Federal and/or State

programs are already under way or

planned for most of the inventory

source sectors to assist States in meeting

their budgets. For example, meeting

individual budget components for

highway vehicles and nonroad engines

can be achieved through Federal

programs without adopting additional

new control strategies. In addition, EPA

is offering to administer certain aspects

of today’s proposed regional NOX

Budget Trading Program in order to

assist States in developing a regulatory

strategy for large stationary combustion

sources.

3. Benefits of Participating in the NOX

Budget Trading Program

Participation in the NOX Budget

Trading Program would enable States

that have been identified in the

proposed transport rulemaking to

achieve the required emissions

reductions from stationary combustion

sources while minimizing the
25920 Federal Register / Vol. 63, No. 90 / Monday, May 11, 1998 / Proposed Rules

11For discussion on this subject, see Section F,

below, that addresses New Source Review.

administrative burden faced by both

States and sources. The SIP revision

process required by the proposed

transport rulemaking would be

significantly streamlined for States

choosing to include the NOX Budget

Trading Program as a part of the SIP.

The EPA proposes that adoption of the

model rule will be considered a SIPapprovable control strategy for the

proposed transport rulemaking. States

electing to participate in the trading

program may either adopt the model

rule by reference or develop State

regulations that are in accordance with

the model rule.

The permitting process under the

trading program would be significantly

streamlined since there will be no need

for enforceable compliance plans and

few circumstances necessitating permit

revisions. Emissions monitoring, a

central requirement of the trading

program, as well as the availability to

the public of emissions data, allowance

data, and annual reconciliation

information, would ensure that

participating States and the public have

confidence that the required emissions

reductions are being achieved.

Cost savings for sources in States

included in the trading program are

projected to be substantial. As estimated

in the ‘‘Proposed Ozone Transport

Rulemaking Regulatory Analysis’’

(September 1997 docket # III–B–01),

annual incremental costs for a ratebased control approach (at 0.15 lbs/

mmBtu) are estimated to be $501

million higher in 2005 than the costs of

participating in the NOX Budget Trading

Program (assuming the same emission

rate) for the 23 jurisdictions in the

proposed transport rulemaking.

Moreover, the annual average cost

effectiveness of emissions reductions

achieved through a regional trading

program for the electric power industry

is projected to be approximately $1,250

per ton by 2010, while the cost

effectiveness of the rate-based approach

is projected to be $2,050 per ton by 2010

(pages 2–24 through 2–27).

Sources included in the trading

program can also expect increased

compliance flexibility, as compared to a

rate-based approach that requires each

affected source to comply with the 0.15

lbs/mmBtu emission rate and

necessitates installation of control

equipment for any affected source that

cannot meet the limit. Participation in

the trading program provides sources

the choice of numerous compliance

strategies. Moreover, sources can choose

to over-comply and generate excess

allowances that can be sold on the

market or, as discussed below, possibly

banked for future use. In addition,

sources may change their control

approach at any time without regulatory

agency approval.

4. EPA’s Proposal

Initially, the following sources would

be included in the NOX Budget Trading

Program: fossil fuel-fired units (i.e.,

stationary boilers, combustion turbines,

and combined cycle systems) that serve

an electrical generator of capacity

greater than 25 MWe; and fossil fuelfired units that do not serve a generator

and that have a heat input capacity

greater than 250 mmBtu/hr. All such

sources located within a State that

chooses to join the trading program

would be required to participate in the

program. Conversely, sources located in

States that do not join the trading

program would not be eligible to

participate. The NOX budget sources

initially included in the trading program

represent about 80 percent of the point

source portion of the 2007 NOX baseline

emissions inventory and about 65

percent of the point source portion of

the 2007 NOX budget as proposed in the

ozone transport rulemaking.

Additionally, these sources represent

about 90 percent of the emissions

reductions required in the proposed

ozone transport rulemaking. This core

group of sources, therefore, captures the

majority of NOX emissions from the

point source sector. States, however,

have the option of extending the

program to include additional point

sources at their discretion, provided

these additional point sources can fulfill

the requirements set forth for the trading

program in this proposal. The EPA is

also taking comment on allowing certain

new and modified major sources to

participate in the trading program at

their discretion as a way of potentially

meeting the new source offset

provisions under section 173 of the

CAA, provided the source meets the

permitting, monitoring, and

accountability requirements of the

trading program.11 The EPA requests

comments on broadening the

applicability of this trading program to

include more types of sources such as

process sources, mobile sources, or area

sources. Commenters should address

each type of source that they

recommend be included in the

applicability of this program. For each

source type, commenters should

describe procedures for monitoring

emissions and identify responsible

parties for the source type. Criteria for

monitoring and for responsible parties

are outlined below. Additionally,

comment is requested on any other

types of concerns or issues associated

with inclusion of these other source

types (e.g., environmental justice; net

cost savings likely to accrue from

trading; administrative costs for sources,

States, and EPA).

Sources in the trading program would

be required to monitor and report their

emissions in accordance with relevant

portions of 40 CFR part 75, which is

currently under revision to provide

greater flexibility to regulated sources.

(40 CFR part 75 revisions will be

proposed in a notice entitled ‘‘Acid Rain

Program; Continuous Emission

Monitoring Revisions’’ that will be

published in the Federal Register in the

near future.) The monitoring of

emissions is necessary for

accountability and to ensure that a ton

from one source in one State is

equivalent to a ton from another source

in the same or another State.

The NOX allowances—each allowance

representing a limited authorization to

emit one ton of NOX—would be the

currency used in the trading program.

An emissions budget and an allowancebased system ensure achievement of

environmental goals within a costeffective, market-based program and can

be implemented through existing

infrastructure. A fixed number of NOX

allowances would be allocated to

regulated sources in each State for each

ozone season in the amount of the NOX

budget set for the trading program in the

State. States would have the

responsibility for allocating allowances

among regulated sources. The proposed

NOX Budget Trading Rule establishes

timing requirements for the submission

of NOX allowance allocations to EPA by

participating States for inclusion into

the NOX Allowance Tracking System

(NATS), which would be operated by

EPA.

In addition to timing requirements,

today’s proposal provides options for a

recommended methodology for States to

allocate NOX allowances to their sources

covered by the NOX Budget Trading

Program. A specific recommendation

would be included in the final trading

rule. States would have the flexibility to

deviate from EPA’s recommendation as

long as the timing requirements (40 CFR

96.41) are met and total NOX allowances

allocated to regulated sources do not

exceed the number of tons that the State

apportions to these sources in the SIP.

This would help ensure that the trading

program can operate efficiently and

effectively across multiple States.

In addition to EPA’s traditional role in

the approval and oversight of the SIP,

EPA would be responsible for managing

the emissions data and market functions
Federal Register / Vol. 63, No. 90 / Monday, May 11, 1998 / Proposed Rules 25921

of the program, as well as performing

annual reconciliation of monitored

emissions and allowances. States

choosing to join the trading program

would be responsible for promulgating

the supporting State regulations;

submitting NOX allowance allocations

to EPA for inclusion in NATS; and

enforcing the permitting, monitoring

and excess emissions requirements. As

established in the proposed transport

rulemaking, the control period would

extend from May through September.

Based on results presented in the

regulatory analysis for the proposed

transport rule that suggest no significant

changes in the location of emissions

reductions resulting from an

unrestricted trading program with a

consistent control level (‘‘Proposed

Ozone Transport Rulemaking

Regulatory Analysis,’’ September 1997,

pages 2–20 and 2–23, docket # III–B–

01), trading could occur across

participating States free from

restrictions (other than the requirement

to comply with existing emissions limits

under title I and title IV of the Act).

These and other program parameters,

however, are predicated on the

proposed transport rule and may be

modified if the final transport rule

differs from the proposal.

B. Evolution of the NOX Budget Trading

Program

Market-based systems to control NOX

emissions have been developed within

the United States, including: The South

Coast Air Quality Management District’s

Regional Clean Air Incentives Market

(RECLAIM) and the Ozone Transport

Commission’s (OTC) NOX Budget

Program. Today’s proposed NOX Budget

Trading Program builds directly upon

the OTC program and recommendations

from OTAG. In addition, EPA held two

public workshops in November and

December of 1997 specifically to solicit

input on the development of the trading

program. The proceedings of these

workshops are also summarized in this

Section.

1. OTC’s NOX Budget Program

The goals and implementation

strategy of the OTC’s NOX Budget

Program are similar to those of the

proposed transport rule and today’s

proposed NOX Budget Trading Program.

Taking into account the work that has

been done by the OTC, EPA has tried to

develop a proposal that will minimize

conflicts between the two programs by

building upon the terms and provisions

in the OTC program. Section V.E of this

preamble further discusses the

integration issues for the two programs.

On September 27, 1994, the OTC

adopted a Memorandum of

Understanding (MOU) committing the

signatory States to the development and

proposal of regionwide NOX emissions

reductions in two phases beginning in

1999 and 2003. The signatory States

were Maine, New Hampshire, Vermont,

Massachusetts, Connecticut, Rhode

Island, New York, New Jersey,

Pennsylvania, Maryland, Delaware, and

the District of Columbia.

The OTC MOU requires reductions in

ozone season NOX emissions from

utility and large industrial combustion

facilities in order to further the effort to

achieve the health-based NAAQS for

ozone. These emissions reduction

requirements will be implemented

through a regionwide cap-and-trade

program. The OTC States, in

collaboration with EPA, industry, and

environmental groups, drafted and

approved a model rule in May 1996.

This model rule serves as a template for

States to adopt their own rules to

implement the budget program defined

by the OTC MOU. In addition to

adopting rules, States in the OTC

program are responsible for allocating

NOX allowances among regulated

sources, certifying monitors and

monitoring plans, auditing and

recertifying sources, and enforcing the

provisions of their State rules. In

addition to EPA’s traditional role in the

approval and oversight of the SIP, EPA

serves as the administrator for the NATS

and the Emissions Tracking System

(ETS), the data systems used to

implement the OTC program. This

entails issuing NOX allowances and

opening accounts, processing transfers

and quarterly emissions reports,

conducting annual reconciliation of

emissions and allowances, and

providing technical assistance to States

and sources as needed.

To implement the program, the OTC

MOU emissions reduction requirements

were applied to a 1990 baseline for NOX

emissions in the Ozone Transport

Region (OTR) to create an emissions

budget for each of the 2 target years:

1999 (Phase II) and 2003 (Phase III).

(Phase I required the installation of

RACT by May 1995.) This budget was

apportioned among all the States; each

State is responsible for allocating its

budget to regulated sources in its State.

Sources are allowed to buy, sell, or trade

NOX allowances, and ultimately must

hold allowances sufficient to cover all

NOX emitted during the ozone season.

Beginning in 1999, the total NOX

emissions from regulated sources cannot

exceed the number of allowances

allocated in the OTR.

In order to ensure that NOX emissions

reductions are achieved and allowances

are fungible, budget sources are required

to monitor and report their NOX

emissions. Most sources use CEMS, as

approved by EPA under 40 CFR Part 75.

For smaller oil-and gas-burning units,

alternative monitoring methods are

available.

At the conclusion of each ozone

season, sources have an opportunity to

evaluate their reported emissions and

obtain any additional NOX allowances

they may need to offset their emissions

during the ozone season. By December

31 of each year, a regulated source

submits a compliance certification

report. Should a source lack sufficient

allowances to offset emissions for the

season, the OTC model rule requires

subtraction of allowances from that

source’s allocation for the following

year. If enough NOX allowances are not

held, an automatic offset will be

imposed during the following year’s

ozone season where an amount of NOX

allowances will be deducted from the

source in an amount equaling three NOX

allowances for each ton of excess

emissions. The source is also subject to

the application of existing State and

Federal enforcement protocols and

penalties.

The NOX allowances that are not used

are automatically carried over into the

following year as banked allowances.

The banking provisions of the OTC

model rule provide for unlimited

banking of allowances with a

‘‘progressive flow control’’ management

scheme to control the withdrawal and

use of banked allowances. (For a more

detailed discussion of banking, see

Section V.E.). Explicit program audit

provisions are established in the OTC

model rule to ensure that the use of

banked NOX allowances does not

threaten the integrity of the system.

Finally, the OTC model rule makes

provisions for possible rule

modifications in the future. This ‘‘midcourse correction’’ provides an

opportunity to revise the 2003

emissions reduction target and budget

and to modify the OTC model rule in

response to refined air quality modeling

or other altered circumstances.

2. OTAG Process

The OTAG, a partnership among the

37 easternmost States and the District of

Columbia, EPA, industry representatives

and environmental groups, was charged

with assessing the significance of ozone

transport and with recommending to

EPA control strategies for reducing this

transport. The OTAG’s initial meetings

were in May and June of 1995, and its

final recommendations were issued to
25922 Federal Register / Vol. 63, No. 90 / Monday, May 11, 1998 / Proposed Rules

12Some sources with annual emissions less than

four tons are included in the program by virtue of

their inclusion in a SIC category in which the

majority of sources emit greater than four tons per

year.

EPA on July 8, 1997 (see 62 FR 60376,

Appendix B). The OTAG completed an

extensive and comprehensive analysis

of ozone transport and control, and EPA

has taken OTAG’s work and conclusions

into account in developing this

rulemaking.

The analysis and conclusions of the

Trading and Incentives Workgroup of

OTAG are particularly relevant to EPA’s

creation of the NOX Budget Trading

Program. The Trading and Incentives

Workgroup was charged with designing

market-based approaches to reduce NOX

emissions. This group identified two

basic paths to market system

implementation—identified as ‘‘Track

One’’ and ‘‘Track Two’’—which could

be used to facilitate achievement of the

statewide budgets delineated in the

proposed transport rulemaking. ‘‘Track

One’’ was defined as an interstate capand-trade program for stationary

sources, administered by a central

regulatory authority, such as EPA.

‘‘Track Two’’ was defined as a marketbased system without an emissions cap.

As discussed above, trading with a cap

better ensures that environmental goals

will be met than trading without a cap.

Therefore, for the purposes of assisting

State achievement of the statewide

budgets set forth in the proposed

transport rulemaking, EPA is focusing

on implementing a ‘‘Track One’’ type of

program with today’s proposed rule and

is building upon OTAG’s analysis and

recommendations regarding the

development of Track One programs.

3. EPA Model Trading Program

Workshops

The EPA held two public workshops

to solicit comments and suggestions

from States and other stakeholders on a

NOX cap-and-trade program prior to

developing today’s proposed NOX

Budget Trading Rule. This Section

describes the workshop process. Greater

detail regarding program development

and feedback received through the

workshop process is provided within

relevant Sections of this preamble.

The trading rule workshops were held

on November 4 and 5, 1997 in

Washington DC, and December 10 and

11, 1997 in Arlington, Virginia. Written

comments during this pre-proposal

phase were welcomed through

December 31, 1997. Each workshop

consisted of a 2-day forum: the first day

was devoted to EPA/State discussions,

and the second day was open to all

interested parties. Over 150 people

participated in each of the workshops.

To facilitate meaningful comments from

these participants, EPA developed

working 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.

The first workshop, addressed the

foundations of the NOX Budget Trading

Program development. To achieve the

required NOX emissions reductions in

the most cost-effective manner, the goals

of the trading program were defined as

meeting the budget, facilitating trading,

and creating a workable program. The

necessity of operating the NOX Budget

Trading Program within the framework

of the proposed transport rulemaking

dictated further requirements, such as a

seasonal control period. Four

fundamental trading rule components

(applicability, monitoring, emissions

limitations, and banking) were

discussed at length.

After broad concepts for the NOX

Budget Trading Program framework

were introduced and discussed at the

first workshop, EPA revised and

augmented the working papers in

accordance with comments and

discussion. At the second workshop,

EPA presented recommendations and

considerations of additional issues,

seeking further input from participants.

The original working papers on

applicability, monitoring, emissions

limitations, and banking were

expanded, and new papers on the use of

output in allocations and the creation of

an energy efficiency set-aside were

introduced in response to interest

expressed at the first workshop. In

addition, a paper presenting a skeleton

of all the components of a model rule

was presented to provide context for

input and an indication of how the NOX

Budget Trading Rule as a whole was

evolving.

The EPA found the workshop process

to be very helpful in generating useful

recommendations for developing the

framework for the model rule. Today’s

NOX Budget Trading Rule proposal

incorporates comments and suggestions

raised at both workshops, along with

nearly fifty written comments received

following the workshops. Listening to

issues important to States through the

workshop process was essential for EPA

to develop a program that would meet

States’ needs. Since the ultimate cost

savings of the regional trading program

will increase with the number of

participating States, it is advantageous

to design a regional trading program that

will likely be adopted by the greatest

number of States. The workshops also

served as a forum to discuss which

program elements should be consistent

among participating States, since

consistency in State-adopted rules is

essential for a viable regional cap-andtrade program. Also of importance in

the workshop process was working with

stakeholders, such as affected sources,

in order to ensure that the trading

program offers the necessary flexibility,

as well as compatibility with other

programs.

The working papers, a detailed

summary of the input received during

both workshops, and written comments

are included in the proposed transport

rulemaking docket (A–96–56, Section

2a).

4. RECLAIM Program

The RECLAIM program, which was

adopted by the South Coast Air Quality

Management District in October, 1993,

and began January 1, 1994, provides

another example of a cap-and-trade

market system. This program regulates

NOX and sulfur oxides (SOX) emissions

from facilities that generally emit four or

more tons per year of either pollutant

from permitted equipment in the South

Coast Air Basin, centered in Los

Angeles.12 The RECLAIM program

currently includes approximately 330

facilities.

The RECLAIM program replaced

command-and-control regulations with

a market program to provide facilities

with added flexibility and lowered

compliance costs in achieving

reductions required to meet State and

Federal requirements for clean air

programs. Facilities in the program are

collectively required to cut their

emissions by a specific amount each

year under the program, resulting in an

almost 80 percent reduction by 2003 for

both SOX and NOX. Each facility

participating in RECLAIM is allocated

RECLAIM trading credits (RTCs) equal

to its annual emissions limit. Initially,

allocations are based on past peak

production and the requirements of

existing rules and control measures for

each facility. Allocations decline

annually through the 2003 compliance

year, then remain constant during

subsequent years. The RTCs, each

representing the limited authorization to

emit one pound of pollutant, expire

annually. Facilities may trade these

RTCs among themselves, providing that

every quarter, each facility holds credits
Federal Register / Vol. 63, No. 90 / Monday, May 11, 1998 / Proposed Rules 25923

13Further, assuming a generator efficiency of

approximately 1⁄3, the 25 MWe cutoff being used for

electrical power producers is roughly equal to a 250

mmBtu/hr cutoff for steam producing boilers,

combustion turbines, and combined cycle systems.

equal to or greater than their actual

emissions for that quarter.

In terms of NOX emitters, the

RECLAIM program generally requires

stationary sources that emit ten or more

tons of NOX annually or which burn any

solid fuels to use CEMS to quantify their

emissions. Smaller sources have

additional monitoring options. Sources

that emit four or more tons of NOX and

less than ten tons may use default

emission rates. They must demonstrate

that these rates are appropriate by

monitoring process variables,

performing periodic emissions testing,

and conducting periodic tune-ups of

equipment. The smallest sources in the

RECLAIM program (those with annual

emissions of less than four tons) may

choose to use default emission rates that

require less extensive testing and

demonstration than those available to

the larger sources.

The program’s annual report for 1996

concluded that RECLAIM was

continuing to meet its emissions

reduction goals; an active trading

market had developed; and the

compliance rate, once it is finalized for

the 1996 compliance year, will be in the

85 to 90 percent range.

C. NOX Budget Trading Program

1. General Provisions

Today’s proposed NOX Budget

Trading Rule will be incorporated into

the 40 CFR as a new part 96. The

subparts of 40 CFR part 96 are described

below. The provisions of 40 CFR part 96

will become effective and apply to

sources only if a State incorporates 40

CFR part 96 by reference into the State’s

regulation or adopts regulations that are

in accordance with 40 CFR part 96.

a. Purpose. Subpart A of today’s

proposed NOX Budget Trading Rule

includes Sections describing: To whom

the NOX trading program would apply;

the standard requirements for

participants in the program (permitting,

NOX allowances, monitoring, excess

emissions, and liability provisions);

exemptions for retired units from the

program requirements; definitions,

measurements, and abbreviations; and

computation of deadlines stated within

the proposal.

b. Definitions, Measurements,

Abbreviations, and Acronyms.

Many of the definitions,

measurements, abbreviations, and

acronyms are the same as those used in

40 CFR part 72 of the Acid Rain

Program regulations, in order to

maintain consistency among programs.

However, additional terms specific to

the NOX Budget Trading Program, such

as control period (the period beginning

May 1 of each year and ending on

September 30 of the same year), NOX

Budget unit (a unit subject to the

emissions limitation under the NOX

Budget Trading Program), and several

others are added. Key definitions are

discussed in relevant Sections below

describing the rule.

c. Applicability. The EPA proposes

that the NOX Budget Trading Rule be

applicable to a core group of 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 is considered fossil fuel-fired if

fossil fuels account for more than 50

percent of the unit’s heat input on an

annual basis. These sources represent

about 80 percent of the point source

portion of the 2007 NOX baseline

emissions inventory and about 65

percent of the point source portion of

the 2007 NOX budget in the proposed

ozone transport rulemaking.

Additionally, these sources represent

about 90 percent of the emissions

reductions required in the proposed

ozone transport rulemaking.

The EPA proposes the above core

group of sources based on their

significant contribution of NOX

emissions, range of cost-effective

emissions reduction options, ability to

monitor emissions, and ability to

identify responsible parties. The

following discussion examines the

monitoring and responsible party

criteria for the NOX Budget Trading

Program’s applicability. Additional

options for the trading program’s

applicability are also presented for

consideration. The EPA solicits

comment on the appropriateness of

including all categories described above

in the core group of sources, whether

the size cut-offs should be higher or

lower for these source categories, and

the appropriateness of including other

source categories in the core group.

i. Monitoring. In general, sources that

participate in a cap-and-trade program

must have the ability to accurately and

consistently account for their emissions.

Accuracy is an important design

parameter because it ensures that

emissions for all sources covered by the

trading program are within the cap. In

addition, because each NOX allowance

will have economic value, it is

important to ensure that emissions (and

thus allowances used) are accurately

quantified. Consistency is an important

feature because it ensures that accuracy

is maintained from source to source and

year to year. It also ensures that the

sources in the trading program are

treated equitably. Finally, consistency

facilitates administration of the program

for both the regulated community and

State and Federal agencies.

When considering what source types

to include in the proposed trading

program (e.g., large boilers, process

sources, mobile sources, area sources),

EPA determined that the core sources

were capable of accurate and consistent

monitoring as outlined below.

• Large Electric Utility Units: For

several years, units serving electricity

generators greater than 25 MWe (with

some exemptions for cogeneration and

nonutility electricity generating units)

have been complying with the title IV

monitoring provisions. The EPA

proposes to include these sources in the

NOX Budget Trading Program.

• Other Large Electricity Generating

Units: Additionally, with deregulation

of electric utilities, it is not clear how

ownership of the electricity generating

facilities will evolve. Therefore, EPA

proposes to include all large electricity

generating sources, regardless of

ownership, in the trading program. As

there is no relevant physical or

technological difference between

utilities and other power generators, the

same monitoring provisions and the size

cut-off of greater than 25 MWe are

applicable to all units which serve

generators.

• Other Large Steam Producing Units:

There is also no fundamental physical

or technological difference between a

boiler, combustion turbine, or combined

cycle system that produces steam for

eventual production of electricity or for

other industrial applications. Thus, EPA

believes that the same monitoring

provisions can be applied to a boiler,

combustion turbine, or combined cycle

system used for industrial steam.13

ii. Responsible Party. Another critical

element of a trading program is to be

able to identify a responsible party for

each regulated source. The responsible

party for a source covered by the trading

program would be required to

demonstrate compliance with the

provisions of the NOX Budget Trading

Program. In general, the large sources

included in the proposed trading

program have readily identifiable

owners and operators that would serve

as the responsible party.
25924 Federal Register / Vol. 63, No. 90 / Monday, May 11, 1998 / Proposed Rules

14 40 CFR part 96 subpart E of the proposed

trading rule addresses the allocation of NOX

allowances to NOX Budget units which includes the

core group of sources as well as any additional

sources the State may choose to include in the

trading program.

iii. Inclusion of Additional Source

Categories. During the public

workshops, several commenters

recommended allowing a State to

include additional sources beyond the

core group into the trading program. As

the applicability criteria proposed today

are intended to define the minimum set

of units required to participate in a

trading program, inclusion of additional

sources is allowed. Some States have

existing or planned programs very

similar to the one proposed today, but

with different applicability criteria (e.g.,

the OTC NOX Budget Program). States

may choose to modify the applicability

language to bring in smaller sources of

the same type as those included in the

core group or additional source

categories. All additional sources (e.g., a

certain industrial process) must meet all

trading program requirements

(including monitoring requirements of

40 CFR part 75 subpart H) and be able

to identify a responsible party. The EPA

believes that smaller sources of the same

type as those included in the core group

should be able to meet the trading

program requirements and, thus, could

be included in a State’s trading rule

without affecting EPA’s streamlined

approval of the SIP as described in

Section V.D of this preamble.

The EPA is also taking comment on

allowing or requiring additional

stationary source categories beyond the

proposed core group to be part of the

trading program. There are three ways

that some or all of the sources included

in these additional categories could be

included. The sources could be

included as part of the core program

applicability, as an additional list of

source categories that a State could

choose to include 14, or they could be

individually opted-in according to the

provisions under 40 CFR part 96 subpart

I of the trading rule.

The EPA believes that there are a

number of additional source categories

that could account for their emissions

using the monitoring protocols in 40

CFR part 75. Bringing a source or source

category that meets these protocols into

the trading program would also not

affect EPA’s streamlined approval of the

SIP. The EPA proposes to develop a list

of additional source categories beyond

the core group that a State may bring

into the trading program without

affecting EPA’s streamlined approval of

the SIP.

If a State chose to bring other source

categories beyond those included in this

proposed list into the trading program,

a more thorough EPA review may be

needed. There are two main reasons for

this review. The first is to ensure that

the monitoring protocols that the State

intended to use for the source or source

category would provide accurate

information and be consistent with the

monitoring protocols being used for the

core sources in the program. The second

is to ensure that EPA could successfully

administer the regional NOX trading

program with the addition of these

sources. For example, EPA would have

to determine that the reporting

requirements for these source categories

could be supported with the

information systems that EPA develops

and the resources that EPA employs to

administer the program.

The EPA believes that the source

categories that are simplest to consider

adding are sources that vent all of their

emissions to a stack, because existing

monitoring protocols (e.g., 40 CFR part

75) can be used to accurately and

consistently quantify mass emissions for

these categories of sources. The two

existing capped NOX trading programs

(the OTC program and the RECLAIM

program) have also focused on these

types of sources.

The OTC program has generally

focused on the same types of sources

that are in the proposed core group,

electrical generating units and large

industrial boilers that burn primarily

fossil fuels. One notable exception to

this is that Connecticut intends to cover

municipal waste incinerators in Phase

III of their program, which starts in

2003. The RECLAIM program has

focused on a larger breadth of sources.

These include industrial boilers and

electrical generating units, but they also

include: internal combustion engines,

heaters, furnaces, kilns and calciners,

ovens, fluid catalytic cracking units,

dryers, fume incinerators/afterburners,

test cells, tail gas units, sulfur acid

production units and waste incinerators.

In both programs, the monitoring

requirements have been based on a

tiered system that requires more

stringent monitoring for units with

higher emissions. Both programs require

CEMS for larger units. In general, this

would include units larger than 250

mmBtu with capacity factors of greater

than 10 percent for the OTC program

and units with emissions of ten or more

tons of NOX per year for the RECLAIM

program. Both programs also offer less

stringent, non-CEMS alternatives for

smaller sources.

While RECLAIM has been able to

account for emissions from a larger

group of source categories than EPA is

proposing to include in the core group,

RECLAIM has had difficulty with some

of these additional source categories.

For instance, RECLAIM’s 1996 audit

explained that the standing working

group on RECLAIM CEMS Technical

issues (a group formed to address issues

relating to RECLAIM monitoring) has

focused on issues ‘‘associated mainly

with the difficult situations faced by

refineries in implementing CEMS

requirements.’’ The audit goes on to

explain that ‘‘this is attributed to the

variability of the fuel used in refinery

equipment [e.g., catalytic cracking units]

as compared to natural gas, the

operational variability of much of the

affected equipment, and the fact that

many of the sources in an older refinery

were never constructed with CEMS

monitoring in mind’’. Additionally,

discussions with RECLAIM staff have

indicated that units that have high

concentrations of particulate emissions

and emit to open baghouses, such as

asphalt heaters and metal melting

furnaces, have been difficult to monitor

because of the high concentration of

particulates. In short, RECLAIM’s

experience has indicated that the

problems faced by these source

categories require more resources for

both the regulated community and the

regulatory agency. Therefore, while EPA

is taking comment on including all

types of stationary sources that emit to

stacks in the program, EPA believes that

some sources are better suited for

participating in a trading program

because their emissions can more easily

be accurately and consistently

quantified.

Based on information available to

EPA at this time, the specific additional

source categories for which EPA is

particularly interested in taking

comment are: Process heaters, internal

combustion engines, kilns and calciners,

and municipal waste incinerators. If any

of these source categories are included

in the final rule as a part of the core

group, EPA is proposing that they be

included with applicability cut-offs

roughly equivalent to the 25 megawatt

cut-off used for electrical generating

facilities and the 250 mmBtu cutoff used

for industrial boilers. The EPA requests

comment on the appropriateness of

these cut-offs.

The EPA is taking comment on these

particular additional categories because

EPA believes these sources have the

capacity to generate significant amounts

of NOX and are capable of monitoring

using the protocols set forth in 40 CFR

part 75. These are also source categories

that are currently participating in the

RECLAIM trading program or those that
Federal Register / Vol. 63, No. 90 / Monday, May 11, 1998 / Proposed Rules 25925

15The phrase ‘‘potential emissions’’ has a

different meaning than the phrase ‘‘potential to

emit’’ used elsewhere by the Agency.

at least one of the States in the northeast

region has considered including in the

OTC NOX Budget Trading Program.

The EPA believes that these source

categories are capable of using 40 CFR

part 75 monitoring because they vent all

of their emissions to a stack or stacks,

which could be monitored using CEMS.

The EPA believes that the particular

monitoring protocols in 40 CFR part 75

that would be applicable for these

sources would be dependent on the fuel

burned, the size of the source, and the

magnitude of the emissions of the

particular unit that was being included

in the program. This is consistent with

the way that the monitoring protocols

are set forth for core sources. For

example, all units that burned solid fuel

(including all municipal waste

combustors and cement kilns and

process heaters that burned coal) would

use a NOX emission rate CEM and a

flow CEM to determine NOX mass.

Units that burn oil or gas (internal

combustion engines and some process

heaters and kilns) would have several

other options depending upon their

size. Large oil or gas units could use a

NOX emission rate CEM and a fuel flow

meter to determine NOX mass.

Infrequently operated units could

qualify to use the emission rate curve

methodology set forth in Appendix E of

40 CFR part 75, and units with potential

emissions 15 of under 25 tons per year

could use the default emission factor

protocols for low mass emitters set forth

in 40 CFR 75.19.

The EPA notes that the currently

proposed provisions in 40 CFR 75.19 do

not contain default emission factors

applicable for these types of units and

requests comments on what factors

would be appropriate. While smaller

and less frequently operated units could

use these simplified monitoring

methodologies, they would also be

allowed to use any of the monitoring

methodologies available to other units

in the program. The low mass emitter

methodology as it is currently proposed

was designed to provide very low

emitting units a very cost effective way

to account for their emissions using

conservative uncontrolled default

emission factors. Because it is based on

conservative uncontrolled default

emission factors, it does not allow units

that use it to quantify emissions

reductions. The owner or operator of a

unit that qualified to use this

methodology might choose to use

another methodology such as the

Appendix E methodology or CEMS

because this would be more

representative of the unit’s actual

emission rate. Another option that is not

in the proposed 40 CFR part 75

rulemaking would be to change the low

mass emitter methodology to allow

units to use unit specific emission rates

and actual unit heat inputs to get more

accurate emissions estimates. Since the

emission rates that were being used

would not be as conservative, units

would have to do more quality

assurance to demonstrate that their

reported emissions were more

representative of their actual emissions.

This might include periodic testing of

emission rates and/or periodic tuning

requirements for the equipment. These

concepts could also be used in

conjunction with controlled default

emission rates to verify that the controls

are operating properly and that the

lower default rates are appropriate. All

of these concepts are similar to the

monitoring methodologies allowed for

the smallest size units in the RECLAIM

program.

The EPA is seeking comment on the

following issues related to monitoring

for both the specific additional source

categories that EPA believes are most

able to account for their emissions

consistently and accurately and any

additional stationary source categories

that emit to a stack. (All comments

related to the use of 40 CFR part 75 for

monitoring for these sources should be

submitted in the separate rulemaking on

40 CFR part 75 revisions—40 CFR part

75 revisions will be proposed in a notice

entitled ‘‘Acid Rain Program;

Continuous Emission Monitoring

Revisions’’ that will be published in the

Federal Register in the near future—

rather than in the instant proceeding.)

1. Can these source categories monitor

and report NOX mass emissions using

the protocols set forth in the proposed

revisions to 40 CFR part 75? If not, why

not?

2. Are there other protocols that

should be included which would

provide emissions measurement and

reporting for these additional sources

with accuracy and consistency

comparable to that provided under 40

CFR part 75?

3. Are the thresholds set forth in 40

CFR part 75 for different monitoring

methodologies appropriate for these

types of sources? For example, in order

to qualify to use the load vs. emission

rate curve methodology set forth in

Appendix E of 40 CFR part 75, a unit

must have an average capacity factor of

less than 10 percent for 3 years and have

a maximum capacity factor of no more

than 20 percent in any one of those

years.

The EPA is also seeking comment on

the following issues related to these

source categories:

1. Should any of these source

categories be included in the core

program applicability, i.e., should their

inclusion be mandatory for a State to

participate in the NOX Budget Trading

Program?

2. Should States, at their option, be

allowed to include any of these source

categories and still receive streamlined

approval of their SIPs?

In addition, EPA is taking comment

on whether any other additional

stationary source categories should be

included. Finally, EPA is taking

comment on whether individual States

including these source categories would

raise concerns about shifting of

production activity (and thus emissions)

to other States that do not choose to

include these categories.

There is more uncertainty for the

ability of source categories not

identified in the core group or in the list

of additional source categories to meet

the trading program requirements.

Adding other source categories not

identified in the final NOX Budget

Trading Program would entail

additional obligations for the State (e.g.,

allocating allowances, certifying

monitors, and enforcing trading program

requirements), would mean that EPA’s

approval of the SIP would not be as

streamlined, and could affect EPA’s

ability to administer the region-wide

program. Therefore, EPA would strongly

encourage any State wishing to

participate in the trading program to

work with EPA before proposing a rule

with expanded applicability criteria

beyond that identified in the final NOX

Budget Trading Rule.

iv. Individual Opt-Ins. The EPA is

proposing that individual point sources,

not otherwise subject to the trading

program and located in a State that is

participating in the NOX Budget Trading

Program, be allowed to opt-in to the

program. For a source to opt-in, it must

meet the same monitoring and

accountability requirements as other

NOX Budget sources. Thus, under the

proposed rule, initial opt-ins would be

boilers, combustion turbines, and

combined cycle systems below the

proposed (or State defined) applicability

threshold. The EPA requests comment

on whether individual opt-ins should

also include any additional sources that

may be included as part of the core

group of sources as a result of the above

discussion under Section iii, Inclusion

of Additional Source Categories. The

proposed opt-in provisions are further

discussed in the opt-in Section of this

preamble.
25926 Federal Register / Vol. 63, No. 90 / Monday, May 11, 1998 / Proposed Rules

16The EPA is aware of concerns relating to

environmental justice issues. These concerns focus

on the possibility that car scrappage programs

might allow significant toxic VOC emissions

increases in specific areas by concentrating region

wide emissions in a local area. The National

Environmental Justice Advisory Council (NEJAC)

has recommended that the Agency involve

stakeholders, analyze local environmental impacts

of existing and proposed trading programs, and

report back to NEJAC. Refer to Document IV–H–10

in EPA Air Docket A–96–56.

v. Additional Options for

Applicability. The EPA solicits

comments on three different options

that may be incorporated into the core

applicability provision of the proposed

trading rule. One option is to expand

the trading program’s core applicability

to include smaller, new sources of the

same type as are now proposed for the

core applicability that commence

operation on or after May 1, 2003, the

start of the first ozone season (the first

compliance period, after September,

2002). For example, the trading program

could apply to all new units serving

electricity generators 10 MWe or greater

and new units not serving electricity

generators and having a heat input

capacity equal to or greater than 100

mmBtu/hr. The possibility exists that a

significant number of smaller new units

would be constructed and that activity

from existing NOX Budget units could

be shifted to these new units. Over time,

the increased number of smaller, new

units not included in the trading

program could make up a significant

portion of the overall NOX emissions in

comparison to the NOX emissions from

the source categories purportedly

included in the NOX Budget Trading

Program. To reduce this potential, it

may be desirable to adjust the

applicability criteria for new units to

ensure that the trading program

continues to cover a significant portion

of the NOX emissions for the source

categories covered by the program.

A second option would be to expand

the core applicability to include all new

and modified sources that meet the

definition of major new or modified

source under the part D nonattainment

NSR program and that are of the same

type of source included in the proposed

core applicability, even if these sources

are smaller than the source size under

option one, above. This would enable

the trading program to integrate more

fully with the NSR program. Under this

option, the trading program

applicability would include all new and

modified units (whether or not they

serve electricity generators) that

commence operation on or after May 1,

2003. If smaller new sources were

included in the trading program, these

sources would have to meet the

monitoring requirements of subpart H of

40 CFR part 75; the proposed revisions

to 40 CFR part 75 contain new protocols

for units with low NOX mass emissions.

Sources’ compliance requirements

could be streamlined significantly if

they could meet their NSR offset

obligations by participating in the NOX

Budget Trading Program (see Section F,

below).

A third option would be to provide an

exemption from the trading program for

existing units that have a very low

federally enforceable NOX emissions

limit (e.g., 25 tons per year), regardless

of the nameplate capacity or the

maximum potential hourly heat input of

the unit. Commenters at the public

workshops raised this option noting that

a trading program generally reduces the

cost of compliance. However, for some

very infrequently used or very low

emitting units, there may be more costeffective ways to ensure any necessary

reductions.

vi. Area and Mobile Sources.

Comments were received at the public

workshops about the opportunity to

include additional sources beyond large

stationary sources in the trading

program. There was not consensus

among workshop participants on this

issue. However, most States in

attendance were opposed to including

area and mobile sources in the trading

program at this time.

As noted above, EPA has identified

key criteria that are important to the

success of the trading program. First, it

is essential that these sources are able to

monitor at a level of accuracy consistent

with the basic objectives of the program.

In addition, the proposed trading

program requires that all sources

covered under the program be held

accountable through a responsible party

for their total emissions that occur from

May through September of each year.

The EPA may consider inclusion of

portions of mobile source or area source

categories which best meet the key

concerns mentioned above (e.g.,

measurement and accounting of all

emissions and identification of

responsible parties). Over the past

decade, EPA and the States have

developed procedures and protocols for

Mobile Source Emissions Reduction

Credit programs. This effort has focused

on the generation of credits for specific

categories of programs, including

scrappage and clean-fueled fleet

programs.

Key issues for the development of

these mobile source programs include

ensuring that the credits generated

reflect real emissions reductions,

development and implementation of an

effective monitoring program, and

identification of a responsible party for

the implementation of the program and

the ensuing emissions reductions. The

EPA requests comment on the adequacy

of the existing programs in addressing

key issues for mobile source credit

programs. Comment is also requested on

whether these types of programs, as

existing or with modification, should be

considered for inclusion in the NOX

Budget Trading Program.

The EPA is interested in innovative

ideas for including area and mobile

sources in cap-and-trade type trading

programs. Comments should address the

categories of each source type that could

most successfully be incorporated into a

cap-and-trade program and that best

address the key issues. Commenters

should address how inclusion of the

specific category recommended may be

implemented and the expected effects of

including these source types in the

program (e.g., integrity of the program,

public support, flexibility, cost savings,

administrative feasibility). Additionally,

comment is requested on any other

types of concerns or issues associated

with inclusion of these source types

(e.g., environmental justice 16).

d. Retired Unit Exemption. 40 CFR

part 96 subpart A of today’s proposal

provides an exemption from NOX

Budget Trading Program requirements

for retired units. The purpose of this

provision is to free retired NOX Budget

units from unnecessary requirements

(e.g., emissions monitoring and

reporting). The EPA proposes an

exemption beginning on the day the

unit permanently retires, requiring no

notice and comment period regarding

the retirement. This provision proposes

that the NOX AAR (i.e., the person

authorized by the owners and operators

to make submissions and handle other

matters) submit notification to the

permitting authority of the NOX Budget

unit’s retirement within 30 days of the

cessation of activity. In response, the

permitting authority would amend the

operating permit in accordance with the

exemption and notify EPA of the unit’s

status as exempt. Criteria within this

provision ensure that all program

requirements prior to the exemption are

fulfilled and records are kept on site to

verify the non-emitting status of the

retired unit. A retired unit could

continue to hold NOX allowances

previously allocated or be allocated

NOX allowances in the future depending

on the allocation provisions adopted by

the State where the retired unit is

located. The number of future year NOX

allowances that a retired unit would be

allocated would be dependent on the
Federal Register / Vol. 63, No. 90 / Monday, May 11, 1998 / Proposed Rules 25927

given State’s allocation system. The

NOX allowance allocations are

discussed below in Section V.C.5 of this

preamble.

In order to resume operation without

violating program requirements, the

NOX AAR of the NOX Budget unit must

submit a permit application to the

permitting authority no less than 18

months (or less, if so specified by the

applicable State permitting regulations)

prior to the date on which the unit is

first to resume operation, to allow the

permitting authority time to review and

approve the application for the unit’s reentry into the program. If a retired unit

resumes operation, EPA proposes to

automatically terminate the exemption

under this part.

e. Standard Requirements. Today’s

proposal delineates, in proposed 40 CFR

part 96 subpart A the standard

requirements, that NOX budget units

and their owners, operators, and NOX

AARs must meet under the NOX Budget

Trading Program. This provision sets

forth and provides references to other

portions of the trading rule for the full

range of program requirements: permits,

monitoring, NOX emissions limitations,

excess emissions, recordkeeping and

reporting, liability, and effect on other

authorities. For example, the permitting,

monitoring, and emissions limit

requirements are discussed in general

and the relevant Sections of the trading

rule are cited. The liability provisions

state that the requirements of the trading

program must be met, and any knowing

violations or false statements are subject

to enforcement under the applicable

State or Federal law. Violations and the

associated liability are established to be

unit-specific, except in the case of

common stacks. The provision

addressing the effect on other

authorities establishes that no provision

of the trading program can be construed

to exempt the owners or operators of a

NOX Budget unit from compliance with

any other provision of the applicable,

approved SIP, any federally enforceable

permit, or the CAA. This provision

ensures, for example, that a State may

set a binding source-specific NOX

limitation and, regardless of how many

allowances a NOX Budget unit holds

under the trading program, the

emissions limit established in the SIP

cannot be violated.

f. Computation of Time. Proposed 40

CFR 96.7 clarifies how to determine the

deadlines referenced in the proposal.

For example, deadlines falling on a

weekend or holiday are extended to the

next business day. These are the same

computation-of-time provisions as are in

the regulation for the Acid Rain

Program.

2. NOX Authorized Account

Representative

40 CFR part 96 subpart B of today’s

proposed NOX Budget Trading Rule

establishes the process for certifying the

NOX AAR and describes his or her

duties. A NOX AAR is the individual

who is authorized to represent the

owners and operators of each NOX

budget unit at a NOX budget source in

matters pertaining to the NOX Budget

Trading Program. Because the NOX AAR

is representing the owners and operators

of all the NOX Budget units at a NOX

Budget source, the NOX AAR must

certify that he or she was selected by an

agreement binding on all such owners

and operators and is authorized to act

on their behalf. The NOX AAR’s

responsibilities include: the submission

of permit applications to the permitting

authority, submission of monitoring

plans and certification applications,

holding and transferring NOX

allowances, and submission of

emissions data and compliance reports.

While the Acid Rain Program refers to

the ‘‘designated representative’’ as the

representative of owners and operators

for non-allowance matters and the

‘‘authorized account representative’’ as

the person for allowance matters,

today’s proposal uses only one term for

all matters and somewhat streamlines

the procedures for selection.

The Agency recognizes that the NOX

AAR cannot always be available to

perform his or her duties. Therefore, the

rule proposes to allow for the

appointment of one alternate NOX AAR

(alternate NOX AAR) for a NOX budget

source. The alternate NOX AAR would

have the same authority and

responsibilities as the NOX AAR.

Therefore, unless expressly provided to

the contrary, whenever the term ‘‘NOX

authorized account representative’’ is

used in the rule, it should be read to

apply to the alternate NOX AAR as well.

While the alternate NOX AAR would

have full authority to act on behalf of

the NOX AAR, all correspondence from

EPA, including reports, would be sent

only to the NOX AAR.

Today’s proposal requires the

completion and submission of the

account certificate of representation

form in order to certify a NOX AAR for

a NOX budget source and all NOX

budget units at the source. There would

be one standard form which would be

submitted by sources to EPA. The EPA

would establish a compliance account

for each unit in the NATS. The form

would include: The plant name, State,

and identifying number (ORIS or facility

code); the NOX AAR name, the NOX

AAR identification number (if already

assigned), address, phone, fax, and email (as well as similar information for

the alternate NOX AAR, if applicable);

the name of every owner and operator

of the source and each NOX budget unit

at the source; and certification language

and signature of the NOX AAR and

alternate, if applicable.

In order to change the NOX AAR,

alternate NOX AAR, or list of owners

and operators, EPA is proposing that a

new complete account certificate of

representation be submitted. The EPA

believes the NOX AAR requirements

afford the regulated community with

flexibility, while ensuring source

accountability and simplifying the

administration of the trading program.

3. Permits

a. General Requirements. The EPA

has attempted to minimize the number

of new procedural requirements for NOX

Budget permitting and to defer,

whenever possible, to the permitting

programs already established by the

permitting authority. The proposed NOX

Budget Trading Program regulations

assume that the NOX budget permit

would be a portion of a federally

enforceable permit issued to the NOX

Budget source and administered

through permitting vehicles such as

operating permits programs established

under title V of the CAA and 40 CFR

part 70. The term ‘‘NOX budget permit’’

throughout this preamble and the NOX

Budget Trading Program regulations

therefore refers to the NOX Budget

Trading Program portion of the permit

issued by the permitting authority to a

NOX budget source.

b. Title V/Non-Title V Permits.

Although many of the NOX Budget

sources that would participate in the

NOX Budget Trading Program must

apply for and receive a title V permit,

this would not be the case for every

NOX budget source. Sources presently

required to have a title V permit are

those that are ‘‘major’’ sources, as

defined in title V and 40 CFR parts 70

and 71. Since there would be some NOX

budget sources that are not major

sources, the NOX Budget Trading

Program would require only that a NOX

budget source have a federally

enforceable permit, rather than require

that each NOX Budget source have a title

V permit. The EPA believes that

requiring all NOX budget sources to

have a title V permit would be unduly

burdensome and that proper

implementation of a NOX Budget

Trading Program can be achieved

through federally enforceable permitting

vehicles in addition to those established

under title V and 40 CFR part 70 or 71.
25928 Federal Register / Vol. 63, No. 90 / Monday, May 11, 1998 / Proposed Rules

For sources required to have a title V

permit, the NOX Budget Trading

Program attempts, wherever possible, to

allow the regulations promulgated by

the permitting authority under title V

and 40 CFR part 70 or 71 to determine

how the NOX budget permit would be

administered. For those sources not

required to have a title V permit, the

NOX Budget Trading Program attempts,

wherever possible, to allow the

permitting authority’s non-title V permit

regulations to govern how the NOX

budget permit would be administered.

Essentially, this would enable the NOX

Budget Trading Program to operate

within the regulatory framework already

established by permitting authorities for

both title V and non-title V permits.

The proposed rule requires that every

NOX budget unit have a federally

enforceable permit. The EPA is

concerned, however, that some States

may not currently have permitting

vehicles for the issuance of federally

enforceable permits to smaller units that

would be subject to the proposed

trading rule. For such States, adoption

of the NOX budget rule would also

require the State either to issue permits

under its title V program to sources that

would not otherwise require title V

permits or to develop other permitting

programs through which federally

enforceable permits could be issued to

such units.

Therefore, EPA requests comment on

the option, for States without programs

for issuing federally enforceable permits

for smaller NOX budget units, of not

requiring such units to obtain federally

enforceable permits. Under this option,

the State’s NOX Budget Trading Rule

would state that NOX budget units that

are not covered by a federally

enforceable permit would still be

subject to the emissions, monitoring,

and other non-permit requirements of

the trading rule, would have their

emissions reported to and recorded on

the EPA-administered Emissions

Tracking System, and would have their

NOX allowance allocations, deductions,

and transfers recorded on the EPAadministered NATS. The EPA requests

comment on whether, under these

circumstances, the units’ obligations

(e.g., to hold sufficient NOX allowances

each control period to cover NOX

emissions and to monitor emissions in

accordance with 40 CFR part 75 subpart

H) would be federally enforceable, with

or without a federally enforceable

permit reiterating the unit’s

requirements under the NOX Budget

Trading Program.

The EPA is soliciting comment on

several other aspects of this issue. First,

EPA is interested in State assessments of

the extent of the problem in issuing

federally enforceable permits to all

sources included in the trading

program. In particular, EPA seeks

information on how many NOX budget

units (or what percent of States’ NOX

budget units) would not be issued

federally enforceable permits, but for

the permit requirements of the proposed

trading rule, and on the extent to which

non-title V permitting programs are

currently established and available for

permitting NOX budget units. Second,

EPA seeks comments regarding the

feasibility of the approach described

above, under which federally

enforceable permits would not be

required for smaller NOX budget units if

the State lacked an existing program for

issuing federally enforceable permits to

such units. Lastly, EPA is interested in

receiving suggestions regarding other

possible approaches to address this

matter.

c. NOX Budget Permit Application

Deadlines. The proposed rule sets the

initial NOX budget permit application

deadlines for units in operation before

January 1, 2000 with either title V or

non-title V permits so that the permits

will be issued by May 1, 2003. May 1,

2003 is the beginning of the first control

period for the NOX Budget Trading

Program, and therefore also the date by

which initial NOX budget permits for

existing units must be effective.

Application submission deadlines are

based on the permitting authority’s title

V and non-title V requirements for final

action on a permit application. For

instance, if a permitting authority’s

permitting regulations allowed 12

months for final action by the

permitting authority on a permit

application, the application deadline for

units in operation before 2000 governed

by the permitting rule would be May 1,

2002 (12 months prior to May 1, 2003).

The same principle applies to NOX

budget units commencing operation on

or after January 1, 2000, except that the

application submission deadline is

calculated from the later of the date the

NOX budget unit commences operation

or from May 1, 2003. The NOX budget

permit renewal application deadlines

are the same as those that apply to

permit renewal applications in general

for sources with title V or non-title V

permits. For instance, if a permitting

authority requires submission of a title

V permit renewal application by a date

which is 12 months in advance of a title

V permit’s expiration, the same date

would also apply to the NOX budget

permit application.

d. NOX Budget Trading Program

Permit Application. The NOX Budget

Trading Program requires that a NOX

budget permit application properly

identify the source and include the

standard requirements under proposed

40 CFR 96.6. The NOX Budget Trading

Program permit application should

include all elements of the program

(including the standard requirements).

Such an approach allows the permitting

authority to incorporate virtually all of

the applicable NOX Budget Trading

Program requirements into a NOX

budget permit by including as part of

such permit the NOX budget permit

application submitted by the source.

Directly incorporating the NOX budget

permit application into the NOX budget

permit and, thus, into the source’s

operating permit or the overarching

permit minimizes the administrative

burden on the permitting authority of

including the NOX Budget Trading

Program applicable requirements, and

mirrors the approach successfully

implemented by many permitting

authorities in issuing Phase II Acid Rain

permits under titles IV and V.

e. NOX Budget Permit Issuance. As

stated earlier, most of the procedures

needed by a permitting authority to

issue NOX budget permits have already

been established by the permitting

authority through permitting vehicles

such as operating permits programs

under title V and 40 CFR part 70 or 71.

Generally, the permits regulations

promulgated by the permitting authority

cover: Permit application, permit

application shield, permit duration,

permit shield, permit issuance, permit

revision and reopening, public

participation, and State and EPA

review. The proposed NOX Budget

Trading Program permit regulations

generally require use of the procedures

under these other regulations and add

some requirements such as NOX budget

permit application submission and

renewal deadlines, NOX budget permit

application information requirements

and permit content, and initial NOX

budget permit effective dates.

f. NOX Budget Permit Revisions. For

revisions to the NOX budget permit, the

NOX Budget Trading Program again

defers to the regulations addressing

permits revisions promulgated by the

permitting authority under title V and

40 CFR part 70 or 71 (for sources

requiring a title V permit) or to non-title

V permitting regulations (for sources not

requiring a title V permit). The proposal

also provides that the allocation,

transfer, or deduction of NOX

allowances is automatically

incorporated in the NOX budget permit,

and does not require a permit revision

or reopening by the permitting

authority. The NOX budget permit must,

however, expressly state that each unit
Federal Register / Vol. 63, No. 90 / Monday, May 11, 1998 / Proposed Rules 25929

must hold enough NOX allowances to

account for NOX emissions by the

allowance transfer deadline for each

control period and that there are offsets

if the unit does not. The EPA believes

that requiring the permitting authority

to revise or reopen a NOX budget permit

each time a NOX allowance allocation,

transfer, or deduction is made would be

burdensome and unnecessary. This is

similar to the approach taken in the

Acid Rain Program, where the transfer

of SO2 allowances are treated as

‘‘automatic permit amendments’’ that do

not require any action by the permitting

authority.

4. Compliance Certification

40 CFR part 96 subpart D of today’s

proposed NOX Budget Trading Rule sets

forth the requirements concerning

certification by the NOX AAR at the end

of each control period that the unit was

in compliance with the emissions

limitation and other requirements of the

NOX Budget Trading Program. The NOX

AAR must submit a compliance

certification report for each NOX budget

unit, by November 30 following the

control period, to both the permitting

authority and the Administrator. This

report must identify the NOX budget

unit and include a compliance

certification statement. The compliance

certification statement must indicate

whether all of the applicable

requirements of the NOX Budget

Trading Program, including the

requirement to hold allowances greater

than or equal to emissions and the

requirement to monitor and report

according to the provisions in 40 CFR

part 96 subpart H of today’s proposal,

were met by the unit for the most recent

control period. The report also allows

the NOX AAR to specify which

allowances (by serial number) should be

deducted from the NOX budget unit’s

compliance account and to specify the

proportion of NOX allowances to deduct

for each unit if a group of units share

a common stack.

The EPA is proposing that annual

compliance certification reports must be

submitted for several reasons. First, the

report provides important information,

such as whether there were any changes

to the unit’s monitoring plan used by

EPA to evaluate the unit’s monitoring

and to determine compliance. Second,

the report provides an opportunity for

the owner or operator to use the

flexibilities allowed in today’s proposal

to choose which NOX allowances would

be deducted to meet emissions

reduction requirements rather than

using the default methodologies for

deducting allowances that are also set

forth in today’s proposal. The EPA is

proposing that a copy of the compliance

certification report be sent to both EPA

and to the permitting authority because

EPA needs the information in order to

administer the compliance period

reconciliation process and the

permitting authority needs the

information in order to ensure

compliance with the SIP. The EPA is

proposing a deadline of November 30

following the control period for

submission because EPA believes this is

sufficient time to compile the

information required in the report,

while still allowing EPA to perform

reconciliation before the next control

period begins.

5. NOX Allowance Allocations

40 CFR part 96 subpart E of today’s

proposed model rule addresses the

allocation of NOX allowances to NOX

budget units. Within each participating

State, the NOX Budget Trading Program

would establish a State trading program

budget (i.e., a cap of seasonal NOX

emissions for all units included in the

program) equal to a fixed total number

of NOX allowances that each State

allocates to its NOX budget units for

each control period. States would have

the ultimate responsibility for

determining the size of their respective

trading program budgets. 40 CFR part 96

subpart E of today’s proposed rule sets

timing requirements for when the

allocations should be completed by each

State and submitted to EPA for

inclusion into the NATS and provides

an option for how States may allocate

NOX allowances to the NOX budget

units.

a. Development of State Trading

Program Budget. Today’s proposal

establishes in 40 CFR part 96 subpart E

the total number of NOX tons for the

NOX Budget Trading Program within a

specific State. The proposed rule sets

the State trading program budget at the

level of NOX emissions apportioned by

an approved SIP for the ozone transport

rulemaking to the State’s sources

meeting the definition of ‘‘NOX budget

unit’’ in the 2007 statewide emissions

budget. Sources meeting the definition

of ‘‘NOX budget unit’’ would include the

sources in the trading program’s core

group of sources as well as additional

sources that a State may choose to

include in the program as discussed

above in Section V.C.1.c. The proposed

transport rulemaking provides States the

flexibility to meet the statewide

emissions budgets with a different mix

of control measures than were

calculated in the transport rulemaking,

thus potentially changing the total

amount of NOX tons apportioned to the

NOX budget units. Therefore, a State

may determine the number of NOX tons

allotted for the State trading program

budget provided the State complies with

the overall requirements of the proposed

transport rulemaking. Once a State sets

the trading program budget, the limit is

set for the total number of NOX

allowances that the State may allocate to

the State’s NOX budget units for any one

control period.

b. Timing Requirements. Today’s

proposed rule sets requirements for

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. This topic was

discussed at both of the public

workshops as explained later in this

Section. The timing requirements

ensure that all NOX budget units 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. The timing

requirements would also contribute to

the efficient administration of the NOX

Budget Trading Program. By

establishing this schedule at the outset

of the trading program, both the States

and EPA would be able to develop

internal procedures for effectively

implementing the NOX allowance

provisions of the trading program. This

is particularly important for EPA with

its role as administrator of the NATS for

all participating States. The timing

requirements would ensure that EPA

would be able to record in the NATS the

time sensitive NOX allowance

allocations for the NOX budget units in

all participating States at the same time

for each control period.

At the public workshops, a range of

options were discussed and commented

on for the timing requirements. The

timing options generally range from

year-by-year allocations, in which the

NOX allowance allocations would be

placed into the NATS on an annual

basis for the upcoming control period;

to a 5 to 10 year allocation where NOX

allowance allocations would be

periodically placed into the NATS for 5

to 10 control periods; to a single,

permanent allocation where the NOX

allowance allocations would be set only

once at the beginning of the trading

program and recorded in the NATS for

an extended, rolling block of time (e.g.,

a rolling 30 year period).

Some commenters stated that timing

options which provide an opportunity

to periodically update the allocation of

NOX allowances to NOX budget units

have certain advantages. First, the

current restructuring of the electricity

industry may significantly affect the mix
25930 Federal Register / Vol. 63, No. 90 / Monday, May 11, 1998 / Proposed Rules

of electricity generators that produce

electricity in the future. As the

utilization of existing electricity

generators changes and new electricity

generators begin operations, an

allocation regime which is periodically

updated would provide an opportunity

to reallocate NOX allowances based on

this changing environment. Second,

depending on the formula that is used

to allocate the NOX allowances, trading

programs that periodically update the

allocations may provide an opportunity

to reward energy efficiency

improvements at specific NOX budget

units. Incentives may be provided for

energy efficiency improvements by

rewarding NOX budget units that

increase their production efficiency over

time with a larger number of NOX

allowances during the next allocation

period. However, commenters also

noted that allocation systems that are

adjusted annually may restrict a NOX

budget unit’s ability to plan for

compliance by creating uncertainty year

to year about the amount of future

allocations that the NOX budget unit

would receive. In addition, annual

allocations prevent a NOX budget unit

from officially transferring future year

NOX allowances because the NATS only

contains the current year’s NOX

allowances under this type of system.

These commenters generally favored an

allocation system that periodically

allocates NOX allowances for 5 to 10

control periods at a time.

Other commenters noted the

advantages of a single, permanent

allocation where the NOX allowance

allocations would be set only once at

the beginning of the trading program.

Permanent allocations provide a long

planning horizon for the NOX budget

units that receive an allocation. Some

commenters noted that permanent

allocations provide a strong incentive

for the owners or operators of high

emitting units to retire or replace the

units. Additionally, permanent

allocations provide an incentive to

improve a NOX budget unit’s energy

efficiency and require less resources to

administer as compared to updating

allocation systems. In a permanent

allocation system, all NOX allowances

are allocated to NOX budget units at the

beginning of the trading program. New

NOX budget units that begin operations

after the allocation of NOX allowances

would be required to obtain NOX

allowances from the market in order to

comply with the trading program

requirements, or there would need to be

a new source set-aside that increased

from year to year, coupled with a

declining allocation to existing sources.

Therefore, commenters that support an

allocation mechanism that provides

NOX allowances to new NOX budget

units were generally opposed to the

permanent allocation approach.

In light of the comments from the

public workshops, today’s proposed

rule attempts to strike a balance

between systems that change the

allocations on an annual basis and

systems that establish a single,

permanent allocation by proposing a

system that allocates NOX allowances

for 5 to 10 years at a time. The proposed

rule includes the following timing

requirements for the allocation of NOX

allowances: by September 30, 1999, the

State would submit to EPA NOX

allowance allocations for the control

periods in the years 2003, 2004, 2005,

2006, and 2007. This initial submission

date would provide the initial allocation

information to NOX budget units more

than 3 years before the start of the

trading program and would enable a

State to include the first five years of

NOX allowance allocations as a part of

its overall SIP submission to meet the

requirements of the proposed transport

rulemaking. After this initial allocation,

two timing options are proposed for the

allocations following the year 2007. One

option, which is set forth in the

proposed rule, is: by January 1, 2003

and January 1 of each year thereafter,

the State would submit to EPA

allocations for the control period in the

year that is 5 years after the applicable

submission deadline. Under this option,

a State would ensure that its NOX

budget units are always allocated 5

years worth of NOX allowances in the

NATS. A second option, on which

comment is also requested, is: By

January 1, 2003, a State would submit

to EPA NOX allowance allocations for

the control periods in 2008, 2009, 2010,

2011, and 2012. The State would

maintain this schedule of submitting

NOX allowance allocations for 5 control

periods by January 1 every five years

after January 1, 2003. This option would

ensure that the State’s NOX budget units

are allocated no less than 5 years, and

as much as 10 years, worth of NOX

allowances in the NATS at any one

time. Under the second option, future

allocations are made less frequently

and, for some years, based on older data

on unit utilization. The second option

would also require a larger new source

set-aside (as discussed below) to span

the longer time frame before new

sources would be incorporated in the

updated allocation. In addition to the

specific options described above, EPA

also solicits comments on the full range

of possible timing requirements

including a single, permanent allocation

system and an annually changing

allocation system.

Today’s proposed trading rule

includes a provision that if a State were

to fail to meet the timing requirements

for submitting NOX allowance

allocations to EPA, EPA would allocate

NOX allowances to NOX budget units in

that State in accordance with 40 CFR

96.42 within 60 days of the applicable

deadline. Section 96.42 is the Section of

the model rule that will contain EPA’s

recommended approach for allocating

NOX allowances to NOX budget units,

which is discussed below. This

provision is designed to ensure that all

NOX budget units included in the NOX

Budget Trading Program would receive

NOX allowance allocations at the same

time for each control period. The EPA

solicits comment on this provision.

c. Options for NOX Allowance

Allocation Recommendation

i. Basis for Developing an Allocation

Recommendation. The EPA proposes

that the final NOX Budget Trading Rule

include a recommended NOX allowance

allocation. This was discussed at length

at the public workshops. Three

approaches to addressing NOX

allowance allocations in the trading

program were presented at the

workshops. First, the rule could

prescribe one method for allocating NOX

allowances. States that choose to

participate in the NOX Budget Trading

Program would need to allocate NOX

allowances as prescribed by the rule.

This option would have the benefit of

going through public comment as a part

of the rule development process. The

second approach was for the rule to

recommend one method for allocating

NOX allowances. States may choose to

use the recommendation, to adjust the

recommendation, or to develop an

allocation method that is completely

different from the recommendation. The

third approach was for the rule to be

silent on the method for allocating NOX

allowances and require the participating

States to independently develop State

specific allocation methods.

Workshop participants covered the

entire range of approaches in their

comments. Commenters in favor of a

prescriptive allocation method argued

that a standard system ensures that

there is equity between NOX budget

units in different States, that the same

environmental goals are pursued within

all participating States (e.g., promotion

of energy efficient units through output

based emission limitations), that all

State programs have the necessary

consistency to promote interstate

trading, and that a standard system
Federal Register / Vol. 63, No. 90 / Monday, May 11, 1998 / Proposed Rules 25931

17 It is important to note that in today’s trading

program proposal, a State would have the flexibility

of determining allocations to its NOX budget units

by whatever system it desires regardless of EPA’s

allocation recommendation.

reduces industry and government

resources necessary to develop and

implement NOX allowance allocations

in each State. On the other end of the

spectrum, commenters in favor of States

having complete flexibility in the

allocation method asserted that it is

important for States to have the freedom

to develop systems that address their

specific needs. Furthermore, as long as

all States follow the timing

requirements for allocations in the

proposed rule, the different State

methods should be sufficiently

compatible to realize the benefits of

trading.

The EPA is sensitive to the argument

that a more prescriptive proposed rule

would ensure a consistent and

administratively efficient multi-state

program that is equitable for similar

NOX budget units. However, EPA also

recognizes that the States which have

commented on this subject have

unanimously supported some degree of

flexibility for developing allocation

methods. Because EPA believes it is

important for as many States as possible

to participate in the NOX Budget

Trading Program, EPA is proposing that

the final rule contain a recommendation

for how States may allocate NOX

allowances but allow States the

flexibility to differ from the

recommendation. By including the

recommended allocation method, the

final rule would provide a complete

model for the NOX Budget Trading

Program. This has the potential to ease

the regulatory process for States that

prefer the recommendation by providing

a rule that can be quickly adapted for

promulgation as a State rule and, as

discussed below, more quickly

considered by EPA as part of SIP

review. In addition, in order to help

facilitate administration of the program,

EPA plans on ensuring that the

necessary data collection protocols exist

to support the option recommended in

the final rule. This would include both

standard data collection requirements

and standard data reporting

requirements.

ii. Options for an Allocation

Recommendation. NOX allowances

could be distributed to NOX budget

units and other private parties by

allocations based on actual operating

data, via auctions, or by a variety of

other mechanisms. Most of the

workshop discussions and comments

focused on how to allocate NOX

allowances based on actual operating

data. In general terms, three different

processes at a unit may be measured

and used as a metric for allocating NOX

allowances: (1) The actual emissions (in

tons of NOX) from the unit, (2) the

actual heat input (in mmBtu) of the unit,

and (3) the actual production output (in

terms of electricity generation and/or

steam energy) of the unit. The option of

allocating NOX allowances based on a

unit’s actual NOX emissions was not

generally recommended because it is

regarded as providing a perverse

incentive by rewarding more NOX

allowances to units that have the

greatest NOX emissions. Heat input and

output are regarded as more neutral

measures of a unit’s utilization, and

therefore, more equitable options for

basing allocations.

The EPA solicits comments on three

options using input or output data for

the allocation recommendation that

would be included in the final trading

rule.17 The first option is to base the

allocation recommendation on heat

input data. This option may be desirable

because accurate protocols exist for

monitoring this data and reporting it to

EPA, and several years of certified data

are available for most of the affected

sources. Additionally, methods

currently exist for calculating

allocations based on heat input data. It

should be noted that in some specific

instances, these protocols are designed

to conservatively estimate heat input.

For instance, new units that do not

certify their monitors by the compliance

deadline, may report heat input using

the unit’s maximum potential heat

input. In another instance, low mass

emitting units that use a simplified

emissions estimation methodology

would also report using the unit’s

maximum potential heat input. In both

of these cases, the potential overreporting of heat input, could lead to a

larger percentage of allowances being

allocated to these units. One potential

option for these instances would be to

require units in these types of situations

to report one heat input value to be used

for emissions estimation purposes and

another less conservative value to be

used for purposes of allowance

allocations. Another option would be to

apply a discount to reported heat input

values in certain circumstances (e.g.,

during periods when monitors are not

certified) for purposes of allocating

allowances. The EPA seeks comment on

whether this issue needs to be

addressed to ensure equitable allocation

of allowances. The other two options

incorporate the use of output data for

the allocation recommendation. The

EPA believes that basing allocations on

output has the potential benefit of

promoting energy efficiency in an

allocation system that periodically

reallocates the NOX allowances (see

Section V.C.9.b of this preamble).

The second option for which EPA

solicits comments would base the

allocation recommendation on heat

input data for the first five control

periods of the trading program (control

periods in the years 2003–2007). The

allocation recommendation would then

be converted to use output data for the

control periods after the year 2007.

Under this option, heat input data

would be used for the first five years

because a number of issues for the

measurement, collection, and use of

output data may not be fully resolved

for all of the NOX budget units that

would be included in the trading

program prior to the time that the

allocation recommendation would need

to be finalized for the initial allocation

period. Section V.C.9.b of this preamble

discusses a number of the issues

associated with measuring and using

output data. To facilitate the use of

output data under this option, EPA

proposes to work with stakeholders to

design the output based system that

would be used after the initial allocation

period. As a part of this output based

system, EPA would amend its Electronic

Data Reporting format so that output

data would be available for States

through EPA’s Emissions Tracking

System.

In order to implement this option,

EPA suggests the following schedule for

developing the output based system that

would be used in the allocation

recommendation for the control periods

after the year 2007: (1) EPA would issue

a proposed system for output based

allocations by the spring of 1999; (2)

EPA would finalize an output based

system by fall of 1999; (3) States

wishing to use an output based system

would adopt the necessary rules by fall

of 2000; (4) output data could be

measured and collected at NOX budget

units during the control periods in the

years 2001 and 2002; (5) output data

would be available for States to

calculate allocations for the control

periods after the year 2007, in time to

meet the allocation timing requirements

established in today’s proposed rule. As

discussed under Section V.C.5.b,

allocations for the control period in the

year 2008 would be submitted to EPA

by January 1, 2003 for inclusion into the

NATS. The EPA solicits comments on

this suggested schedule for establishing

a method for output based allocations

and comments on the issues raised

under Section V.C.9.b of this preamble.
25932 Federal Register / Vol. 63, No. 90 / Monday, May 11, 1998 / Proposed Rules

18The EPA is soliciting comment in Section F,

below, on allowing certain sources, to which the

trading program would not be generally applicable,

to opt into the NOX Budget Trading Program in

order to fulfill the new source offset provisions

under section 173 of the CAA. If this alternative is

incorporated into the final trading rule, then the

size of the allocation set-aside should be based on

the expected new sources that are covered by the

general applicability criteria and the additional

sources that may opt in.

The third option for which EPA

solicits comments would base the

allocation recommendation on output

data, to the extent practicable, for all

NOX budget units from the start of the

trading program. The allocations for the

first five control periods of the trading

program would be based on output data

currently reported to government

agencies other than EPA (such as the

Department of Energy’s Energy

Information Agency, the Federal Energy

Regulatory Commission, or State Public

Utility Commissions). Depending upon

the availability of information, it may be

necessary in this option to use output

for electricity generating facilities and

input data for non-electricity generating

facilities for the initial allocation period.

The allocation recommendation would

then be converted to use output data for

all NOX budget units for the control

periods after the year 2007. As in the

second option described above, EPA

proposes to work with stakeholders to

design a complete output based system

that would be used after the initial

allocation period. Unlike the output

data used in the initial allocation

period, the allocations for control

periods after the year 2007 would be

based on output data that would be

reported in EPA’s Electronic Data

Reporting format and designed

specifically to support a NOX allowance

allocation system. The EPA suggests the

same schedule as outlined above in the

second option for developing the

complete output based system for

allocating NOX allowances.

iii. Framework for an Allocation

Recommendation. As discussed above

under Section V.C.5.c.i, EPA proposes

to include a specific recommendation in

the final trading rule for allocating NOX

allowances to NOX budget units. This

allocation recommendation may be

based on either input or output data as

outlined in one of the three options

presented above under Section

V.C.5.c.ii. In addition to the data used

to support the allocations, EPA also

solicits comments on two other key

elements for an allocation

recommendation: (1) Using a portion of

the State’s NOX allowances as a setaside for new NOX budget units for

control periods for which the unit was

not allocated NOX allowances, and (2)

using either a fuel neutral or output

neutral calculation to determine

allocations for NOX budget units.

Today’s proposed rule includes an

example of a specific allocation

methodology that uses heat input data

and addresses the above key elements.

This allocation methodology would be

appropriate for implementing an

allocation system entirely based on heat

input data or for implementing the

initial allocation period of an allocation

system that starts out using input data

and later is converted to the use of

output data. The allocation

methodology would need to be modified

for the use of output data to implement

an allocation system that eventually

converts to output data or for an

allocation system that begins with using

output data. The EPA solicits comment

on the following allocation methodology

for using input data and on the

appropriateness of using the basic

framework of this methodology for an

output based allocation system.

Furthermore, the allocation

methodology establishes an allocation

set-aside account equaling 2 percent of

the State trading program budget for

each control period for new NOX budget

units (i.e., units that commence

operation during or after the period on

which general NOX allowance

allocations are based). Based on

analyses conducted using the Integrated

Planning Model (IPM) and on the

proposal to reallocate allowances every

five years, 2 percent appears to be a

reasonable portion of NOX allowances to

set aside for new units. The remaining

98 percent of the NOX allowances are to

be allocated to existing NOX budget

units. The EPA requests public

comment on the use of a set-aside and

on the proposed size of the set-aside,

which EPA believes should be large

enough to accommodate all new units

entering the trading program.

Initial, unadjusted allocations to

existing NOX budget units, which equal

98 percent of the State trading program

budget, 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

the years 2003 through 2007, the heat

input used in the allocation calculation

equals the average of the heat input for

the two highest control periods for the

years 1995, 1996, and 1997. For the

control periods after 2007, the heat

input equals the heat input measured

during the control period of the year

that is six years before the year in which

the allocations are being calculated.

Therefore, the allocation calculation

combined with the timing requirements

discussed under Section V.C.5.b of this

preamble results in the following

schedule: The allocation for the control

period in 2008 should be submitted to

EPA by January 1, 2003 and based on

heat input data for the control period in

the year 2002; the allocation for the

2009 control period should be

submitted to EPA by January 1, 2004

and based on 2003 control period heat

input data. This schedule would

continue indefinitely or until revised

(e.g., to base allocations on output)

through rulemaking. The heat input data

used for calculating the allocations is to

be data collected in accordance with the

requirements of 40 CFR part 75 for units

that were subject to these requirements

for the year or years specified by the

allocation calculation. For units not

subject to 40 CFR part 75 requirements

for the year or years specified by the

allocation calculation, the heat input

data used in the calculation should be

the best available heat input data

reported by the unit to the State. Once

the initial allocation calculation is

completed for all the existing NOX

budget units, the allocation for each unit

would be adjusted proportionately so

that the total allocation equals 98

percent of the State trading program

budget.

A separate, allocation set-aside for

new units would be established for each

control period. Each set-aside would

initially hold NOX allowances equal to

2 percent of the NOX allowances in the

State trading program budget 18. NOX

allowances in the allocation set-aside

would be available to NOX budget units

for control periods that the unit was not

allocated allowances because the unit

commenced operation during or after

the period on which general NOX

allowance allocations are based. To

receive NOX allowances from the

allocation set-aside, the NOX AAR for a

unit would submit to the State a NOX

allowance request, in writing or in a

format specified by the State. The

request would be for no more than 5

consecutive control periods, starting

with the control period during which

the unit is projected to commence

operation. For the 6th year and later,

there would be sufficient operating data

for the unit to be incorporated into the

NOX allowance allocations with existing

NOX budget units. The NOX allowance

request would be submitted prior to

May 1 of the first control period for

which NOX allowances are requested

and after the date on which the State

issues a permit to construct the NOX

budget unit. The NOX AAR may not

request an amount of NOX allowances

for each control period that exceeds 0.15

lb/mmBtu multiplied by the NOX
Federal Register / Vol. 63, No. 90 / Monday, May 11, 1998 / Proposed Rules 25933

budget unit’s maximum design heat

input (in mmBtu) for the hours in the

control period starting with the first day

in which the unit is projected to

operate. Maximum design heat input is

used because actual heat input

information for the baseyear period used

for existing units would not be available

since the new unit would have

commenced operation during or after

the baseline period.

Under this proposal, the State would

review and allocate NOX allowances to

new units requesting NOX allowances

according to the order that the requests

were received. Upon review, the State

would make any necessary adjustments

to the requests according to the

requirements governing NOX allowance

requests. 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 and verified by the

State, the State would allocate the full

(or adjusted) amount of NOX allowances

requested to the NOX budget unit. If the

set-aside for the control period for

which NOX allowances are requested

has a smaller amount of NOX

allowances than the number requested

and verified, the State would deny in

part the request and only allocate the

remaining number of NOX allowances in

the set-aside to the NOX budget unit.

Once the set-aside for a control period

has been depleted of all NOX

allowances, the State would not allocate

any NOX allowances to additional units

requesting NOX allowances for the

control period. NOX budget units with

NOX allowance requests that were

denied in whole or part would be

responsible for obtaining the necessary

amount of NOX allowances from the

NOX allowance market in order to

demonstrate compliance with the

provisions of the proposed rule. The

State would act on all NOX allowance

requests within 60 days upon receipt of

the request and notify the NOX AAR

that submitted the request and the EPA

of the number of NOX allowances (if

any) allocated for the control period.

After September 30 of each year, the

EPA would transfer NOX allowances

remaining in the set-aside for the

control period to the set-aside for the

following control period.

For new NOX budget units that have

been allocated NOX allowances from the

allocation set-aside, the EPA would

deduct NOX allowances following each

control period based on the unit’s actual

utilization for the control period,

determined in accordance to the

requirements under 40 CFR part 96

subpart H of the proposed rule. Because,

as discussed above, 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 on allocating NOX

allowances to existing units. Without

the adjustment procedures, a new unit

(e.g., a peaking unit) could be allocated

NOX allowances assuming utilization far

out of proportion to actual utilization

and the set-aside could be insufficient to

provide NOX allowances for all new

units at such an allocation level.

Under the actual utilization

adjustment procedure, EPA would

deduct a number of NOX allowances

according to the following equation:

NOX allowances deducted for actual

utilization adjustment = (Number of

NOX allowances allocated for control

period)¥((actual control period

utilization (in mmBtu) × 0.15 lb/

mmBtu)). The NOX allowances

deducted must have the same or an

earlier compliance use date as the year

of the control period for which NOX

allowances were allocated from the setaside. (As discussed below in Section

V.C.7.b of this preamble, the proposed

rule reflects unlimited banking of NOX

allowances once the trading program

begins in 2003. However, EPA is

proposing several options concerning

banking (including no banking) and

requesting comment on them.) The NOX

AAR may identify the serial numbers of

the NOX allowances to be deducted. In

the absence of such identification, the

EPA would deduct NOX allowances on

a first-in, first-out basis. The EPA would

transfer the NOX allowances deducted

into the State’s set-aside for the

following control period.

If additional NOX allowances are

moved into a set-aside resulting from

the transfer of NOX allowances from a

previous year’s set-aside or from the

actual utilization adjustment, the State

would allocate NOX allowances to those

NOX allowance requests that were

denied in whole or in part pursuant to

the NOX allowance request provisions

under this Section of the proposed rule.

However, requests for NOX allowances

by new units would not be granted

retrospectively for control periods that

have ended.

An additional option that was

considered for inclusion in an EPA

recommended allocation methodology

was the use of a price signal auction for

a portion of NOX allowances. The

transparency of the first SO2 allowance

auctions under Title IV accelerated

price discovery and provided useful

information to industry for making

compliance decisions in the early years

of the program. The value for this type

of auction for NOX allowances was

discussed at the December public

workshop. Commenters generally

questioned the need for a price signal

auction for NOX allowances because of

the market instruments currently

available from the private sector,

including several allowance price

indexes. Based on these comments, EPA

did not include a price signal auction in

the proposed options for the allocation

recommendation. The EPA solicits

comment on this option.

The EPA solicits comments on any

other allocation recommendation that

may be made in the final rule.

Comments should be of comparable

detail to the example outlined in this

Section.

6. NOX Allowance Tracking System

40 CFR part 96 subpart F of today’s

proposed trading rule covers the NATS.

The proposed rule is intended to be

reasonably consistent with the NATS

that was developed for implementation

of the OTC’s NOX Budget Program. Such

consistency would help to allow the

integration of the two programs in the

future. It would also save industry and

government the time and resources

necessary to develop new tracking

systems.

The NATS would be an automated

system used to track NOX allowances

held by NOX budget units under the

NOX Budget Trading Program, as well as

those allowances held by other

organizations or individuals.

Specifically, the NATS would track the

allocation of all NOX allowances,

holdings of NOX allowances in

accounts, deduction of NOX allowances

for compliance purposes, and transfers

between accounts. The primary role of

NATS is to provide an efficient,

automated means of monitoring

compliance with the NOX Budget

Trading Program. The NATS would also

provide the allowance market with a

record of ownership of allowances,

dates of allowance transfers, buyer and

seller information, and the serial

numbers of allowances transferred.

Although today’s proposal assigns each

allowance a unique serial number, EPA

requests comments on the necessity of

serial numbers and on whether the

administrative burden to allowance

holders and EPA of tracking and

reporting serial numbers outweighs the

benefits of serial numbers for tax and

accounting purposes.

The EPA is proposing that NATS

contain three primary types of accounts:

compliance accounts, overdraft

accounts, and general accounts.
25934 Federal Register / Vol. 63, No. 90 / Monday, May 11, 1998 / Proposed Rules

Compliance accounts are created for

each NOX budget unit, and overdraft

accounts are created for each source

with two or more NOX budget units,

upon receipt of the account certificate of

representation form. General accounts

are created for any organization or

individual upon receipt of a general

account information form.

a. Compliance Accounts. As part of

the implementation of the NOX Budget

Trading Program, EPA is proposing to

establish compliance accounts for each

NOX budget unit upon receipt of the

account certificate of representation

form. These accounts would be

identified by a 12-digit account number

incorporating the plant’s Office of

Regulatory Information System’s (ORIS)

code or facility identification number as

well as the number of the unit for which

the compliance account is established.

Allocations for the first six years (2003–

2008), as prescribed by each State,

would be transferred into these

compliance accounts prior to the first

control period in 2003. Prior to the

second control period, in 2004, and

each year thereafter, allocations for the

new sixth year, as prescribed by each

State, would be transferred into each

compliance account (e.g., in 2004, year

2009 NOX allowances would be

allocated). As for the deadline for

transferring NOX allowances to cover

emissions in the control period (i.e., the

NOX allowance transfer deadline of

midnight on November 30), each

compliance account (supplemented as

discussed below by an overdraft

account) must hold sufficient NOX

allowances to cover the NOX budget

unit’s NOX emissions for that year’s

control period.

b. Overdraft Accounts. Today’s

proposed trading rule provides for an

overdraft account that would be

automatically created for each source

with two or more NOX budget units, and

represented by the source’s NOX AAR.

The NOX AAR may choose whether he

or she wishes to utilize the account by

transferring allowances into the account

before the annual reconciliation process.

NOX allowances transferred into the

overdraft account for a NOX budget

source by the NOX allowance transfer

deadline would be available for

deduction during annual reconciliation

if a NOX budget unit at that source fails

to hold sufficient NOX allowances to

cover emissions in its compliance

account. This is similar to the approach

used in the OTC NOX Budget Program

and provides additional flexibility for

owners and operators in complying with

the requirement to hold NOX allowances

covering emissions. If the compliance

account and the overdraft account

together do not contain enough NOX

allowances, then the unit would be out

of compliance. The compliance account

must be depleted of all NOX allowances

before the overdraft account is utilized.

The proposed rule would deduct NOX

allowances from the overdraft account

beginning with the unit having the

lowest NATS account number. The unit

that fails to hold sufficient NOX

allowances between the compliance

account and the overdraft account

would be subject to the same

consequences that would apply were

only its compliance account being

tapped for compliance, including the

automatic excess emissions offset

deduction and the applicable penalties

under State law and the CAA. If the

final trading rule includes provisions for

the banking of NOX allowances, such

provisions would apply to the NOX

allowances held in the overdraft

accounts as well as those held in

compliance accounts.

Today’s proposal allows the NOX

AAR to identify specific serial numbers

for deduction from a compliance

account. In the absence of a specific

identification of NOX allowances to be

deducted, a FIFO (first-in, first-out)

method would determine the order in

which NOX allowances would be

deducted. The proposal does not,

however, allow for the identification of

specific NOX allowances to be deducted

from an overdraft account because NOX

allowance deductions from the overdraft

account would take place automatically,

in a set order, after the NOX allowance

transfer deadline has passed.

c. Compliance. Once a control period

has ended, NOX budget units would

have a window of opportunity (i.e.,

until the NOX allowance transfer

deadline of midnight on November 30)

to evaluate their reported emissions and

obtain any additional NOX allowances

they may need to cover the emissions

during the ozone season. On November

30 of each year, the NOX AAR must also

submit a compliance certification report

for each NOX budget unit. Should the

NOX budget unit not obtain sufficient

NOX allowances to offset emissions for

the season, three NOX allowances for

each ton of excess emissions would be

deducted from the unit’s compliance

account for the following control period.

EPA believes that it is important to set

up this automatic offset deduction

because it ensures that non-compliance

with the NOX emission limitations of

this part is a more expensive option

than controlling emissions. The

automatic offset provisions do not limit

the ability of the permitting authority or

EPA to take enforcement action under

State law or the CAA.

d. General Accounts. Today’s

proposal allows any person or group to

open a general account in NATS. These

accounts would be identified by the

‘‘9999’’ that would compose the first

four digits of the NATS account

number. Unlike compliance accounts

and overdraft accounts, general

accounts cannot be used for compliance

but can be used for holding or trading

NOX allowances (e.g., by NOX allowance

brokers or owners of multiple NOX

budget units). General accounts are

currently used for SO2 allowances in the

Acid Rain Program.

To open a general account, a person

or group must complete the standard

general account information form,

which is similar to the account

certificate of representation that

precedes the opening of a compliance

account and any overdraft account. The

form would include: the NOX AAR

name, phone, fax, and e-mail (as well as

similar information for the Alternate

NOX AAR, if applicable); NOX AAR

mailing address; the names of all parties

with an ownership interest with the

respect to the NOX allowances in the

account; and certification language and

signatures of the NOX AAR and

alternate, if applicable.

Revisions to information regarding an

existing general account are made by

submitting a new general account

information form which would be sent

to EPA in all cases, whether the form is

used to open a new account, or revise

information on an existing one. The

EPA would notify the NOX AAR cited

on the application of the establishment

of his or her account in the NATS or of

the registration of requested changes.

7. Banking

a. General Discussion. Banking is the

retention of unused allowances from

one control period for use in a later

control period. Banking allows sources

to create reductions beyond required

levels and ‘‘bank’’ the unused

allowances for use later. Generally

speaking, banking has several

advantages: it can encourage earlier or

greater reductions than are required

from sources, stimulate the market and

encourage efficiency, and provide

flexibility in achieving emissions

reduction goals (e.g., by allowing for

periodic increased generation activity

that may occur in response to

interruptions of power supply from nonNOX emitting sources). In addition, a

banked allowance is one less ton of

pollutant emitted in a given year. On the

other hand, banking may result in

banked allowances being used to allow

emissions in a given year to exceed a

State’s trading program budget. The
Federal Register / Vol. 63, No. 90 / Monday, May 11, 1998 / Proposed Rules 25935

following discussion summarizes the

general issues associated with banking

and then presents four specific banking

options for consideration.

i. Banking After the Start of the

Program. Banking after a program starts

and the budget is imposed allows

sources to retain any allowances not

surrendered for compliance at the end

of each control period. Once the trading

program budget is in place, sources may

over-control for one or more seasons

and withdraw from the bank in a later

season. This type of banking provides

the general advantages as described

above (encourages early reductions,

stimulates the market, and provides

flexibility to sources), while also

potentially causing NOX emissions in

some control periods to be greater than

the allowances allocated for those

seasons.

ii. Banking Prior to the Start of the

Program. Banking of credits or

allowances for reductions prior to the

start of the program allows sources to

accumulate NOX allowances for

compliance use once the program

begins. In addition to the general

advantages of banking, this option

allows sources to possibly delay

required emissions reductions for some

sources once the program begins by

using banked allowances for

compliance. As OTAG analyses

concluded, the accumulation of

significant amounts of allowances prior

to the start of the program could defer

the date at which the trading program

budget is actually achieved, even

though the early reductions may enable

some air quality benefits to be realized

sooner than anticipated. Early

reductions can be realized either

through the award of early reduction

credits or the creation of a phased-in

program.

iii. Management of Banking. Banking

clearly introduces another variable into

a cap-and-trade program; it may, in fact,

inhibit or prohibit achievement of the

desired emissions budget in a given

season. To limit this variability and

promote achievement of a budget,

OTAG suggested several different

management options: Adjusting the

trading program budget downward by

decreasing allocations so that expected

variations would stay below the desired

emissions level; imposing an

accelerated rate of retirement on

allowances used for emissions during

ozone episodes; establishing an absolute

limit on the amount of banked

allowances that could be used each

season or a discount rate on the use of

banked allowances over a given level

(flow control); and applying a

transaction-specific discount rate to all

banked allowances used in the future. In

considering these options identified by

OTAG for managing the use of banked

allowances, it is important to remember

that the model trading rule is being

developed to attain the seasonal budget

set forth in the proposed transport

rulemaking.

The ‘‘flow control’’ option would

allow banking, but would discourage

the ‘‘excessive use’’ of banked

allowances by establishing either an

absolute limit on the number of banked

allowances that could be used each

season or a rate discounting the use of

allowances over a given level. In the

latter case, the number of banked

allowances in the system would be

tabulated each year to determine what

percentage of the overall budget was

banked, and therefore whether flow

control could affect the use of banked

allowances for compliance in the

upcoming control period. If this

percentage were below a predetermined

amount (e.g., 10 percent as is the case

with the OTC, since this level roughly

equated emissions variations in years of

low nuclear power availability), all

banked allowances could be used

without discounts in the upcoming

control period. If this percentage were

above the predetermined amount, a

withdrawal ratio would be applied to

each account holding banked NOX

allowances that could be used for

compliance to determine the number

that could be used to cover emissions at

a 1-to-1 rate, and the number which, if

used, would have to be used at a 2-to1 rate. It is important to note that the

withdrawal ratio would be applied only

to banked NOX allowances that could be

used for compliance purposes, and

therefore only to NOX allowances

banked in compliance and overdraft

accounts. The withdrawal ratio would

be determined each year prior to the

control period to which it would

pertain, but it would not be applied

until the time of compliance

certification at the end of that control

period. This schedule provides the

sources one full control period to plan

for the application of flow control on

their compliance and overdraft

accounts.

To illustrate flow control, assume the

total trading program budget across all

participating States was 300,000

allowances, and 35,000 allowances were

banked following a control period.

Since more than 10 percent of the total

trading program budget is banked, a

withdrawal ratio would be applied to all

accounts holding banked allowances

that can be used for compliance in the

upcoming control period. In this case,

the ratio applied to accounts with

banked allowances 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

this upcoming 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 NOX

allowances to cover emissions in the

upcoming control period, the 1,000

allowances would equate to 930 tons of

NOX emissions (860 + 140/2).

In this manner, flow control manages

the use of banked allowances beyond a

predetermined level, here 10 percent of

the region wide trading program budget.

This discourages but does not prohibit

the use of banked allowances and, thus,

mitigates the effects of ‘‘excessive use’’

of banked allowances in a given control

period. While limiting the annual flow

of emissions on the one hand, flow

control also preserves the benefits of

banking, granting flexibility to sources,

stimulating the market and maintaining

some incentive to over-comply. Since

the withdrawal ratio is known to

sources prior to the control period,

sources have certainty about how

excessive use of banked allowances will

be treated, and both States and EPA can

minimize their involvement and let the

market function relatively unfettered.

b. Options. The EPA is proposing, and

requests comment on, four options for

whether and how banking may be

incorporated into the NOX Budget

Trading Program: (1) Banking is not a

feature; (2) banking begins when the

trading program begins; (3) units may

generate early reduction credits for use

after the start of the program and

banking continues after the program

begins; and (4) banking begins with the

first-phase of a two-phase trading

program and continues thereafter. The

EPA is not adopting or recommending

an option in this proposal. In the final

rule, EPA intends to adopt a specific

approach to banking based on the

comments received on the four options

and any other approaches suggested by

commenters. Although EPA has not

focused on any one approach at this

time, the proposed rule reflects, for the

purpose of illustration, option 2 (i.e.,

banking when the trading program

begins and without any management of

banked NOX allowances).

Each of the four options is discussed

below. If banking is allowed,

development of a banking provision

involves trade offs on the following

design features: the length of time (if

any) permitted for reductions yielding

NOX allowances prior to the start of the
25936 Federal Register / Vol. 63, No. 90 / Monday, May 11, 1998 / Proposed Rules

trading program as determined in the

proposed transport rulemaking; the

level at which these reductions can be

generated; and the type of management

imposed on the use of banked NOX

allowances. The longer the period of

time allowed for early reductions and

the less stringent the level at which NOX

allowances can be generated, the more

concern there will be about exceeding

the program budget once the program

begins. Because of this concern, arising

from the potentially numerous banked

NOX allowances available at the start of

the program, there may be a need for

management of the use of banked NOX

allowances.

The EPA used the IPM model to help

investigate the ramifications of different

options. The results of this analysis

were presented in the working paper on

emissions banking presented at EPA’s

December 1997 model rule workshop,

entitled ‘‘Second Draft Working Paper:

Emissions Banking. December 1997

Analysis of Banking in a NOX Trading

Program’’. This paper is available as

item number V–A–28 in Docket No. A–

96–56 of the Air and Radiation Docket

(see the ADDRESSES Section at the

beginning of today’s notice for further

guidance on obtaining information from

the docket). The EPA hopes that these

analyses will help stakeholders consider

the trade-offs in designing programs

with banking and provide EPA

comments on the best way to structure

a trading program. Commenters should

consider how best to strike a balance

between the advantages of flexibility,

encouraged early reductions, and

potential lower compliance costs versus

the potential exceedance of prescribed

budgets due to excessive use of banked

allowances in a given control period.

i. Option 1: No Banking. Not allowing

banking in the NOX Budget Trading

Program would result in the automatic

retirement of any NOX allowances not

surrendered for compliance following

each control period. Under this option,

the only NOX allowances available for

compliance in each control period

would be those allocated within the

budget for that control period. As a

result, States would be assured of

achieving their budgets established

under the NOX Budget Trading Program

each control period. However, the ‘‘no

banking’’ option does eliminate

incentives for early reductions, reduces

the program’s flexibility, and may

contribute to a ‘‘use or lose’’ mentality

for the use of allowances by sources at

the end of each control period.

ii. Option 2: Banking After Program

Start Only. This option, which does not

provide for early reductions, but allows

banking of NOX allowances after the

start of the program, was the approach

used in the supporting analysis for the

proposed transport rulemaking. This

option is presented without the

imposition of a management system on

the use of banked NOX allowances

because the volume of banked NOX

allowances is not expected to be

excessive absent the opportunity for

early reductions.

iii. Option 3: Early Reduction Credits.

This option allows for the generation of

early reduction credits for some time

period prior to the start of the trading

program; the NOX allowances resulting

from early reductions are banked for use

once the program starts, and banking is

an option throughout the life of the

program.

Sources demonstrating tonnage

emissions reductions in excess of a

predetermined level in the year or years

prior to the start date for the program

earn early reduction credits; each credit

is redeemed for a one-time award of one

NOX allowance. The NOX allowances

awarded for the generation of early

reduction credits may be created as

additional to the trading program

budget, or may be drawn from the

budget. If the NOX allowances awarded

for early reductions come from the

trading program budget, each State

participating in the NOX Budget Trading

Program would establish a set-aside of

a small percentage of its seasonal

trading program budget for purposes of

awarding the generation of early

reduction credits. For example, this setaside could be 2–3 percent of the State

trading program budget, pulled from

each of the first five years of allocated

NOX allowances. The resulting set-aside

could be distributed at the conclusion of

the period in which early reduction

credits can be generated, on a pro rata

basis. Any NOX allowances not awarded

from this reserve would be returned to

the State trading program budget for

distribution as allocations. The EPA

requests comment on this option of

taking early reduction credits from the

State trading program budgets and

details regarding how this could be

accomplished, if in a different manner

than that suggested here.

If the NOX allowances awarded for

early reductions originate from within

the trading program budget, their award

could pose a threat to achievement of

the budget once the program begins,

even though future allocations will

necessarily be decreased by an amount

equivalent to the NOX allowances

awarded for early reductions. The shift

of available NOX allowances to the

beginning of the program could

potentially result in more emissions

than budgeted levels in the early years

of the program. If the NOX allowances

awarded for early reductions are created

outside of the trading program budget,

there should be even more concern

regarding potential exceedance of the

trading program budget since all

awarded NOX allowances are in excess

of budgeted levels of emissions and

thus, potentially have a more

pronounced and extended impact on the

achievement of the trading program

budget. This concern is addressed later

in this Section.

The award of NOX allowances for

early reductions under the NOX Budget

Trading Program, whether from within

or outside of the budget, would require

a case-by-case determination by

participating States that the reductions

claimed were real, surplus, and

quantifiable. Part of this determination

would be made based on monitored

data. This monitored data should be

based on the same standards that are

being used to support the ongoing

trading program. Therefore, any source

wishing to receive early reduction

credits would be required to have

monitors in place and certified for the

entire period that the awards are being

made. Early reduction credits could be

determined and awarded on either a

unit-, source-, company-, or State-level

basis. A unit- or source-level

determination would necessitate a more

substantial proof of legitimacy due to

concerns of load-shifting to other units

or sources. Load shifting is a particular

concern in this instance because

relatively few units would be pursuing

the early reduction credits, leaving the

majority of similar sources at a less

stringent control level or no required

level. Generally speaking, the

opportunity for load shifting from

sources subject to some emission

control (e.g., units seeking early

reduction credits) increases with the

number of similar units or sources that

are not subject to an equivalent

emission control. Whether the load

shifting is to units or sources with the

same owner or with a different owner as

compared to the original unit or source,

such load shifting could eliminate the

environmental benefit of reduced

emissions at the original unit or source.

The applicant would have to

demonstrate that the requested credits

were real and surplus, and not the result

of load or production shifting. A

company or State-level determination,

on the other hand, would reduce, but

may not eliminate, load-shifting

concerns. The activity of all units

owned by the company in the State (but

not any other units) would be accounted

for in the consideration of eligibility for
Federal Register / Vol. 63, No. 90 / Monday, May 11, 1998 / Proposed Rules 25937

early reduction credits. The EPA solicits

comment on using a company-level

determination in order to reduce

concern over utilization shifting.

Incorporating early reduction credits

into the NOX Budget Trading Program

would also require determinations of

the control level beyond which to award

early reduction credits and the time

period during which the credits can be

earned. The control level should be set

within the range of the already

established title IV and title I levels and

the level in the proposed transport

rulemaking; EPA solicits comment on

the level of 0.15 lb/mmBtu as proposed

in the transport rulemaking. The time in

which the credits could be earned could

be either one, two, or three years prior

to the start of the program; EPA solicits

comment on a time period of two years.

If the NOX allowances awarded for early

reductions come from outside of the

trading program budget, a control level

above 0.15 lb/mmBtu or a time period

longer than two years may threaten

program integrity by allowing the

possibility of a large bank being

established prior to the start of the

program that could significantly delay

achievement of the budget. If the NOX

allowances are awarded from within the

budget, this control level and time

period are still appropriate to protect

program integrity, and also ensure that

the NOX allowance set-aside to reward

early reductions does not withdraw too

many NOX allowances from the future

trading program budget, and pose undue

burden on sources in the program.

Placing a limit on the number of NOX

allowances which may be awarded for

early reductions, such as two percent of

the first budget period, and reducing the

first period budget by a like amount,

could help to protect program integrity

and ensure that too many allowances

are not withdrawn from the first budget

period.

The existence of early reduction

credits in the NOX Budget Trading

Program could necessitate the

consideration of a management scheme

to control the use of banked allowances.

A management scheme could be

required even if the NOX allowances are

withdrawn from the budget, since

exceedance of the budget would still be

quite possible due to the shift of

available NOX allowances to the

beginning of the program. As discussed

above, a flow control management

scenario, whereby the use of banked

NOX allowances over a predetermined

percentage of the trading program

budget would be constricted by a

weighted withdrawal ratio, would be

one way of discouraging the ‘‘excessive

use’’ of banked allowances throughout a

control period. Under this approach, a

withdrawal ratio of two banked NOX

allowances to one for the current control

period would be imposed on the use of

some banked NOX allowances whenever

the percentage of banked NOX

allowances in the NOX Budget Trading

Program region exceeds 10 percent of

the trading program budget for that

control period. EPA acknowledges other

percentages and withdrawal ratios are

also feasible, but solicits comment on 10

percent and 2-for-1 as reasonable levels

to ensure program integrity while

providing the opportunity to bank NOX

allowances. The proposed flow control

management scenario is the same

system used in the OTC’s model rule to

manage the use of banked NOX

allowances. This system simply acts as

a safeguard against excessive

withdrawals of banked allowances in a

given control period; if large amounts of

banked NOX allowances are not used, it

will not be invoked.

These four factors together—the origin

of the NOX allowances awarded for

early reductions, the time period for

reductions, the level beyond which

credits can be earned, and the

subsequent management scheme for

banked NOX allowances—together

determine the impact of the award of

early reduction credits on achievement

and maintenance of the NOX Budget

Trading Program budget.

iv. Option 4: Phased-In Program. For

this option of a program utilizing

phased-in emissions reductions, an

initial limit or cap would be set at a

level representing an emissions

reduction less stringent than the desired

budget that is the ultimate goal of the

trading program. A NOX budget source

could over-control with respect to this

preliminary level at one or more units

and accrue NOX allowances, building

up a bank to be used to defer emissions

reduction requirements when the first

phase level is ratcheted downward to

achieve the final budget under the

trading program. Banking would begin

with the first phase of the program and

be allowed throughout the life of the

program.

Implementing the NOX Budget

Trading Program as a phased-in program

requires similar trade-offs to those

required to implement early reduction

credits, including consideration of the

time period of the first phase during

which banked allowances can be

accumulated, the stringency of the

control level and resulting budget

mandated in the first phase, and the

management scheme imposed. The

implementation of a phased-in program,

however, unlike the award of early

reduction credits, requires all sources to

participate in the first phase. In effect,

a phased-in program creates an earlier

compliance deadline for sources in all

States participating in the NOX Budget

Trading Program. Unlike an early

reduction credit approach, a phased-in

approach would not require applicants

to demonstrate that NOX allowances

were surplus of load shifting or States

to conduct case-by-case reviews of

applications because load shifting

would be much less of a concern. This

lowered environmental risk should

allow a less stringent performance level

to be used in the early phase, which

would increase the opportunity to bank

NOX allowances. Monitoring and

reporting in accordance with prescribed

methodologies would be required by the

new, earlier compliance deadline in

order to track compliance and ensure

the integrity of reductions and resulting

generation of excess allowances.

To provide time for such monitoring

and reporting to be put in place for all

NOX budget units, the first phase could

be no sooner than two years prior to the

start of the trading program at the level

of control and timing mandated in the

proposed transport rulemaking. The

EPA solicits comment on a time period

of two years. As would be the case with

early reduction credits, the level of

control for the first phase would be set

at a level within the range of the title IV

level and the level established in the

proposed transport rulemaking. The

EPA solicits comment on a level of 0.25

lb/mmBtu, a somewhat less stringent

level than that considered without a

phased-in program. However, even this

level of control would enhance the

ability of units to bank NOX allowances

and so would increase the need for a

management scheme to ensure program

integrity. The EPA also solicits

comment on a flow control approach

incorporating a withdrawal ratio of two

to one for some banked NOX allowances

used for compliance in the current

control period whenever the percentage

of banked allowances in the NOX

Budget Trading Program region exceeds

10 percent of the trading program

budget for that control period. Once

again, it is important to note the

interdependence of the time period for

reductions prior to the program start,

the level beyond which allowances can

be earned, and subsequent management

scheme for banked NOX allowances.

8. Allowance Transfers

The EPA is proposing that once a NOX

AAR is appointed and an account is

established in the NATS, NOX

allowances can be transferred to or from

the accounts with the submission of an

allowance transfer form to EPA.
25938 Federal Register / Vol. 63, No. 90 / Monday, May 11, 1998 / Proposed Rules

Transfers can occur between any

accounts at any time of year with one

exception: transfers of current and past

year allowances into and out of

compliance accounts and overdraft

accounts are prohibited after the NOX

allowance transfer deadline (November

30) of each year until EPA completes the

annual reconciliation process by

deducting the necessary allowances.

There would be one standard NOX

allowance transfer form. This form

would be submitted to the EPA in all

cases. The form would include: The

transferror and transferee NATS account

numbers; the transferror’s printed name,

phone number, signature, and date of

signature; and a list of allowances to be

transferred, by serial number.

The EPA is moving towards electronic

submission of allowance transfers. Full

capability is expected by 2000. AARs

would be informed of developments

and/or requirements for electronic

submissions as they arise.

9. Emissions Monitoring and Reporting

a. Requirements for Point Sources. 40

CFR part 96 subpart H of today’s

proposed model rule sets forth the

emissions monitoring and reporting

requirements for the NOX Budget

Trading Program. The EPA is proposing

that units subject to the NOX Budget

Trading Program be required to meet the

monitoring and reporting provisions

that are contained in a proposed new 40

CFR part 75 subpart H to the monitoring

and reporting provisions of the Acid

Rain regulations. These revisions are

being proposed in a separate rulemaking

that contains a new subpart H of 40 CFR

part 75, which addresses how NOX mass

emissions (i.e., tons of NOX emitted)

should be monitored and reported and

which references relevant provisions in

the other subparts of 40 CFR part 75

(revisions to be published in the Federal

Register in the near future). All

comments on the new subpart H of 40

CFR part 75 should be submitted in the

separate rulemaking on 40 CFR part 75

revisions rather than in the instant

proceeding.

The EPA is proposing that States use

the proposed 40 CFR part 75 subpart H

to support the monitoring and reporting

for this program to ensure that

emissions are consistently and

accurately monitored and reported from

unit to unit and from State to State. This

consistency and accuracy in monitoring

is necessary to ensure that a NOX

allowance actually represents one ton of

emissions and that one ton of reported

emissions from one source is equivalent

to a ton of reported emissions from

another source. This establishes the

integrity of the NOX allowance (i.e., the

authority to emit one ton of NOX) and

instills confidence in the market

mechanisms that are designed to

provide sources with flexibility in

achieving compliance. The consistency

and accuracy in reporting is necessary

to ensure that compliance can be

determined quickly and consistently

and that buyers and sellers of NOX

allowances can determine the value of

what they are trading.

The EPA believes that the NOX mass

emissions monitoring provisions in 40

CFR part 75, as it is proposed to be

revised, provide a reasonable and cost

effective way to consistently and

accurately monitor NOX mass. One of

the main advantages of using these

provisions to support this program is

that many of the NOX budget units, i.e.,

existing utility units subject to the Acid

Rain program, are already required to

meet the monitoring and reporting

requirements in the existing 40 CFR part

75. Under the proposed revisions to 40

CFR part 75, the main new requirement

for these units would be to calculate and

report hourly, quarterly, seasonal and

annual NOX mass emissions. In almost

all cases, these values could be

determined using existing 40 CFR part

75 monitoring systems.

In addition to sources currently

subject to the Acid Rain Program, many

additional sources in the OTC that are

not subject to the Acid Rain Program,

but that are covered by both the OTC’s

NOX Budget Program and this proposal,

will be meeting many of the monitoring

and reporting requirements in existing

40 CFR part 75 by April 1, 1998 in order

to comply with the OTC’s NOX Budget

Program. Units covered by the proposed

trading rule but not required to use the

provisions of 40 CFR part 75 to comply

with either the Acid Rain Program or

the OTC’s NOX Budget Program will

also benefit from using monitoring and

reporting requirements that are based in

large part on existing 40 CFR part 75

requirements that are already being used

by a large number of units. Since

existing State monitoring regulations

vary greatly, and since many States do

not currently require the monitoring and

reporting of NOX mass, it is necessary,

for purposes of supporting the proposed

trading program, to create consistent

monitoring and reporting requirements.

If 40 CFR part 75 monitoring and

reporting are used in the trading

program, units not currently using 40

CFR part 75 will have the benefit of

much of the expertise and software that

has already been developed to support

the Acid Rain Program and the OTC

NOX Budget Program.

The notice of the proposed

rulemaking concerning revisions to 40

CFR part 75 sets forth in detail the

proposed revisions related to

monitoring NOX mass emissions. While

comments on the proposed revisions to

40 CFR part 75 (including proposed 40

CFR part 75 subpart H) should be

submitted in the separate 40 CFR part

75 rulemaking, an overview of the 40

CFR part 75 revisions is provided here

to assist commenters in the instant

rulemaking. The proposed 40 CFR part

75 revisions require units to determine

NOX mass emissions by monitoring NOX

emission rate (in lbs/mmBtu) and heat

input (in mmBtu) on an hourly basis

and by multiplying those two values

together. Coal units and other units that

burn solid fuel that are covered by the

NOX Budget Trading Program would be

required to measure NOX emission rate

using a NOX emission rate CEM

consisting of a NOX concentration CEM

and a diluent CEM (CO2 or O2 CEM) and

measure heat input using a diluent CEM

and a flow CEM. All gas and oil units

covered by the NOX Budget Trading

Program would be allowed to use this

option or alternatively could measure

heat input by using a fuel flowmeter and

performing fuel sampling and analysis.

This option for determining heat input

is set forth in Appendix D of 40 CFR

part 75 and referenced in the new

subpart H of 40 CFR part 96. Gas and

oil units that qualified as either peaking

units or low mass emitting units under

40 CFR part 75 would also have

additional lower cost monitoring

methodologies available to them.

Peaking units, for example, could do

source testing to create heat input

versus NOX emission rate curves. Then

based on hourly measurement of heat

input from a fuel flowmeter and fuel

sampling and analysis, the heat input

versus NOX emission rate curves would

be used to estimate the hourly NOX

emission rate. This option for

determining NOX emission rate is set

forth in Appendix E of 40 CFR part 75

and referenced in 40 CFR part 96

subpart H. This rate would be used in

conjunction with heat input determined

using the provisions in Appendix D of

40 CFR part 75 to determine NOX mass.

A unit that qualifies as a low mass

emitting unit could use a default NOX

emission rate and the unit’s maximum

rated hourly heat input to determine

NOX mass emissions. The low mass

emissions unit provisions are in

proposed 40 CFR 75.19 and referenced

in 40 CFR part 96 subpart H.

The proposed 40 CFR part 75 subpart

H requires units to report hourly NOX

mass emissions throughout the year,

rather than just in the seasonal control

period. The EPA is proposing to make
Federal Register / Vol. 63, No. 90 / Monday, May 11, 1998 / Proposed Rules 25939

the monitoring and reporting

requirements year round, as under the

Acid Rain Program, because EPA

believes that this will facilitate

integration with other monitoring and

reporting requirements, such as New

Source Performance Standards (NSPS)

requirements, Compliance Assurance

Monitoring (CAM) requirements and

other State requirements. In the long

run, EPA believes that this

consolidation can help to ease the

overall monitoring and reporting burden

on sources.

The proposed changes to 40 CFR part

75 also highlight several additional

issues that are particularly pertinent to

monitoring NOX mass emissions. These

include: an alternative way to measure

NOX mass emissions using a NOX

concentration CEM and a flow CEM,

specific requirements for monitoring

NOX emission rate at common stacks

and heat input at common stacks and

common fuel pipes, and the reporting of

NOX mass emissions on a total hourly

basis rather than on an hourly mass

emissions rate basis. More information

on these issues can be found in the

notice of proposed rulemaking for 40

CFR part 75 which will be published in

the Federal Register in the near future.

All comments on the proposed revisions

to 40 CFR part 75, including any related

to NOX mass emissions, should be

submitted in the 40 CFR part 75

rulemaking proceeding, rather than in

the instant proceeding.

While units would be required to

meet the technical monitoring

requirements set forth in 40 CFR part

75, the general and administrative

requirements related to monitoring are

set forth in the proposed trading rule.

These include: compliance dates,

prohibitions, requirements for

certification and recertification of

monitors, recordkeeping and reporting

requirements and procedures for

requests for alternatives to the

monitoring requirements.

The EPA is proposing that units that

commence operation before January 1,

2000 have certified monitors installed

and operating for this program by May

1, 2001, which is earlier than the

compliance date (May 1, 2003) for

emissions reductions in the proposed

transport rulemaking and this trading

program. Since no precertification of

emissions reductions is needed for

sources to make trades, it is important

to make sure that the monitoring that is

used to certify the emissions is verified

before the start of the trading program.

While up-front certification of monitors

provides a great deal of assurance that

sources would be able to account for

their emissions, up-front reporting

verifies that they can report their

emissions. In addition, other aspects of

the trading program that are discussed

in other parts of this proposal, including

a rolling allocation scheme based on

updated monitored data and the

banking of allowances before the

beginning of the program, would require

monitoring earlier than May 1, 2003. If

a unit commences operation on or after

January 1, 2000, it would be required to

have certified monitors installed and

operating by the later of: May 1, 2001;

or 180 days after the unit commences

operations or, if the unit is subject to

any Acid Rain emission limitation, 90

days after the unit commences

commercial operation. Deadlines for

installation and certification of monitors

are also established with regard to new

stacks or flues constructed after the

general installation and certification

deadlines. Regardless of the deadline for

installation and certification of

monitors, if any unit is operating on or

before May 1, 2001, but the monitors for

that unit are not certified by May 1,

2001, the owner or operator must still

account for emissions beginning on May

1, 2001 so that this data will be

available to support the allocation

provisions and possible provisions

providing the opportunity to bank

allowances before the beginning of the

program. Similarly, if any unit is not

operating on or before May 1, 2001 the

owner or operator must account for

emissions from the date and hour the

unit commences operation. The owner

or operator has three options for

accounting for emissions until all of the

required monitors are certified:

Reference method monitoring;

maximum potential values; or data from

the monitors before certification is

completed if certain quality assurance

and data validation procedures are

followed. This would be consistent with

the requirement to hold NOX allowances

for all emissions in the ozone season

and would assist with NSR integration,

which requires accounting of all

emissions.

The prohibitions Section of the

trading rule sets forth several general

prohibitions that would apply to all

units included in the program. Units

would not be able to use alternatives to

the requirements in proposed subpart H

of 40 CFR part 96 (and proposed revised

40 CFR part 75) unless that alternative

was approved according to the

procedures set forth for approval of

alternatives to the monitoring

requirements. The procedures for

requests for alternatives to the

monitoring requirements vary

depending upon whether or not the unit

involved is also subject to 40 CFR part

75 for purposes of compliance with title

IV of the Act.

Units subject to 40 CFR part 75 for

purposes of compliance with an Acid

Rain emission limitation would already

meet most of the requirements for the

NOX Budget Trading Program, by

meeting the requirements for title IV.

Before an owner or operator could

deviate from the monitoring

requirements for 40 CFR part 75 for this

trading program or both this program

and title IV, approval would have to be

obtained from EPA. The EPA would

take action on the petition for

alternative monitoring in consultation

with the appropriate State agency. This

differs from the requirements for

sources not subject to title IV who

would need approval from both the

State and EPA. The EPA believes that

this is appropriate because EPA

currently has authority to approve

petitions for these sources. The

additional requirements would involve

reporting new data and, in a few cases,

use of monitors not being used for

purposes of title IV. The NOX budget

units subject to title IV would continue

to meet the same requirements as other

units subject to title IV, but would be

required to include some additional

data in the quarterly reports that they

are already submitting for title IV

purposes. This data would include

hourly, quarterly, annual and ozone

season NOX mass emissions data. In

addition, if a unit subject to title IV had

to install additional monitors to comply

with this program, those monitors

would have to meet the certification and

recertification requirements of the NOX

Budget Trading Program. The only

reason that a unit would have to install

additional monitors for this program

would be if its currently installed

monitors did not allow it to calculate

NOX mass. This would only be an issue

if a unit shared a common stack with

other units and chose to measure NOX

emission rate at the unit level, but

measured heat input at the common

stack level. For purposes of the Acid

Rain Program, this unit would be

allowed to apportion heat input to the

unit level. While EPA believes this

methodology is accurate enough for

purposes of using heat input to

determine reduced utilization, EPA does

not believe that it is accurate enough for

purposes of determining NOX mass;

EPA’s rationale is discussed in the

preamble to the 40 CFR part 75

rulemaking which will be published in

the Federal Register in the near future.

The NOX budget units not subject to

title IV would be subject to essentially

the same requirements for certification
25940 Federal Register / Vol. 63, No. 90 / Monday, May 11, 1998 / Proposed Rules

and recertification and monitoring and

reporting. The owner or operator of a

unit would be responsible for initially

certifying monitors. The owner or

operator would be responsible for

providing the permitting authority both

a monitoring plan and notification of

the time and date of the original

certification tests in advance of those

tests. The owner or operator would also

be responsible for recertifying monitors

if any major changes were made to the

monitors and would be required to

report emissions and other supporting

data on a quarterly basis.

An owner or operator wishing to

deviate from the monitoring

requirements set forth in 40 CFR part 75

would have to petition for approval to

do so. Unlike certifications and

recertifications which would only have

to be approved by the permitting

authority, these petitions would have to

be approved by both EPA and the

permitting authority. There are three

main reasons that petitions would have

to be approved jointly. The first is that

in order to ensure that emissions are

accounted for equivalently from source

to source and State to State, it is

important that there be consistency in

approving any alternatives to the

allowed monitoring methodologies. By

working with the permitting authority

in all of the approvals for alternatives,

EPA can help ensure this consistency.

The second is that in order for EPA to

fulfill its role as the repository for

emissions data, it is important that all

of the data be reported in a consistent

format and that EPA be aware of any

deviations from that consistent format.

The final reason is that EPA cannot

approve a SIP that allows a State the

unlimited ability to approve alternatives

not specifically spelled out in the SIP.

If a State wants to approve a

methodology that is not specifically part

of the SIP, EPA would have to be

involved in this approval.

b. Output Information. In general, the

information available concerning the

operation of a unit can be placed into

one of three categories: Input, process,

and output. Heat input is a measure of

input; specifically, it is the chemical

energy of the fuel burned. Variables

related to combustion, such as

temperature, are process variables.

Measures of output from a unit include

emissios; steam energy, and, for a unit

serving an electricity generator,

electrical power produced. Today’s

proposal presents options for allocating

NOX allowances based on actual

information on unit operation. The EPA

has received comments that allocations

of NOX allowances under the trading

program should be made on the basis of

electrical and/or steam output, rather

than heat input, measurement.

A system where NOX allowances are

reallocated on an ongoing basis (as is

being proposed today) may decrease the

incentives for reducing NOX emissions

through the use of more efficient fuels

or more efficient equipment. For

example, assume a certain unit

currently uses 500 mmBtu/hr to

generate 50 MWe. Under a simple heat

input based allocation scenario, if that

unit increased its efficiency by 20

percent, so that it could produce

50MWe while using only 420 mmBtu/

hr, it would lose 20 percent of its NOX

allowances in the next NOX allowance

reallocation, even though it is producing

the same electricity. However, under an

allocation scheme based on output, if

this unit’s electricity production did not

change, it would receive the same

number of NOX allowances. Since a

decrease in the amount of fuel needed

is generally accompanied by a decrease

in NOX emissions, a unit increasing its

efficiency would either have more NOX

allowances to sell on the market or

would need to purchase less NOX

allowances to be in compliance. Thus,

basing allocations on output gives units

additional efficiency options for

compliance, which should reduce the

overall cost of the program. As an

additional benefit, decreases in fuel

usage would reduce emissions of other

pollutants such as SO2, mercury, and

carbon dioxide (CO2).

However, EPA is concerned that there

may be some issues not yet fully

addressed concerning allocation of NOX

allowances based on output. First are

issues concerning the development of

measurement protocols for output.

Measurement protocols are critical for

making a fair and expeditious allocation

of NOX allowances. There are two

general locations at which power output

of an electricity generating facility could

be measured: gross generation at the

generator, or net generation after plant

power requirements have been

consumed. Gross generation seems less

appropriate, since an allocation based

on output would primarily be intended

to address efficiency improvements and

allocation by gross generation fails to

account for a plant’s power

requirements whose efficiency could be

improved. To the extent the power is

sold, net generation could be measured

at the point of sale. Measurement at the

point of sale has an advantage in that it

is tracked by the source and the

dispatch authority for crediting sales. A

workable program requires only that all

participants measure generation at the

same general location and with the same

method.

A second set of issues in allocating

using output concerns how to relate

product output to emissions output.

Electrical generation and distribution

systems at plants can be complex, with

multiple units emitting through one or

more stacks and serving multiple

generators. If output is to be measured

at the plant level, then it would be

appropriate to measure total emissions

from the plant, even if that meant

measuring emissions from small units.

Alternatively, the electrical output from

small units could be measured and

subtracted from plant-level electrical

output to avoid the need to monitor

emissions from small or infrequently

used units.

For units producing steam that does

not feed into a generator, different

issues arise. These sources have steam

production in addition to (or instead of)

power generation as their final output.

Allocating emissions to both types

(steam producing and power generating)

of sources would require the

development of a method for converting

the steam energy to an electrical power

equivalent. The method would likely

require assumptions about the efficiency

of the conversion. The use of any

general efficiency assumption, without

considering the configuration and

operation of each individual plant,

could lead to penalizing plants that

operate more efficiently than the general

case (by not allocating enough

allowances) and giving windfalls to

plants that operate less efficiently than

the general case (by allocating more

allowances than warranted).

The EPA solicits comments on how

the issues discussed above could be

addressed in order to allow States to

base the initial NOX allowance

allocations for this trading program on

an output measure or convert an

allocation system initially based on

input to one based on output. As further

explained in the allocation Section of

the preamble, EPA may use this

information in the development of a

final rule that would provide States the

opportunity of using output based

allocations.

10. Opt-Ins

The NOX Budget Trading Program

includes provisions allowing for units

that otherwise would not be subject to

the trading program and that are located

in a State that is participating in the

trading program to voluntarily elect to

participate (i.e., opt in). The opt-in

provisions can further reduce the cost of

complying with the NOX budget by

allowing those units, which may not

otherwise be required to reduce NOX

emissions for a State to meet its budget,
Federal Register / Vol. 63, No. 90 / Monday, May 11, 1998 / Proposed Rules 25941

19Today’s proposal also solicits comment on

allowing sources not meeting the above description

to opt in, at their discretion, if they are subject to

part D nonattainment NSR preconstruction

permitting requirements as major new sources or

major modifications to existing sources and they

can meet the other eligibility criteria of this trading

program. The trading program budget in the SIP

would not be increased for the new emissions at

these opt-in sources because they would be entering

the trading program in order to offset their new

emissions (see Section F, below).

to opt in to the trading program and

make incremental, lower-cost

reductions. The NOX allowances freed

up by the opt-in source’s control action

can be sold to other NOX budget units

for their compliance with the NOX

emission limitation. In general, units

that opt in are treated like other NOX

budget units and are subject to the same

requirements to monitor, to hold

allowances to account for emissions,

and to have a NOX budget permit. Units

that have opted in may also elect to

withdrawal from the program if certain

requirements are met.

a. Applicability for Opt-In Units.

Today’s proposal allows sources (i.e.,

units) to opt-in that are similar to, but

smaller in capacity than, the sources

covered under the proposed

applicability provisions of the NOX

Budget Trading Program. A State would

account for the opt-in unit in the State’s

SIP by adding the opt-in unit’s NOX

emissions to the trading program budget

in the SIP and subtracting the opt-in

unit’s NOX emissions from the part of

the SIP not covered under the NOX

Budget Trading Program.19 The

applicability Section of this preamble

discusses and requests comment on the

participation of other source types and

sizes under the trading program. It also

discusses whether other additional

source categories should be included in

the trading program. The sources in

these categories could be included as

part of the core program applicability,

they could be included as an additional

list of source categories that a State

could choose to include as core sources,

or they could be listed as sources that

could choose to individually opt in.

b. Allowance Allocations for Opt-In

Units. Today’s proposal allocates NOX

allowances to an opt-in unit on a yearby-year basis. An opt-in unit is required

to monitor and report the NOX emission

rate and the heat input according to the

provisions under 40 CFR part 96 subpart

H of the proposed rule for one control

period prior to the unit entering the

trading program. The NOX emission rate

and heat input measured at the unit

during this initial period of time would

become the unit’s baseline emission rate

and baseline heat input, respectively.

The EPA requests comment on whether

emissions rate or heat input data from

periods prior to this initial period

should also be used to set these

baselines. The allocation for an opt-in

unit is calculated by multiplying the

lesser of the unit’s baseline emission

rate (in lb/mmBtu) or the most stringent

State or Federal emissions limitation

applicable to the NOX budget opt-in

source during the control period by the

lesser of the unit’s baseline heat input

or the unit’s actual heat input (in

mmBtu) measured during the control

period prior to the allocation

calculation. The State would notify EPA

by December 1 to allocate NOX

allowances to an opt-in unit for the next

year’s control period. While the

proposal recommends opt-in allowance

allocations based on heat input, EPA

solicits comment on whether the

allocations should be based on output.

The options for using output and the

factors considered are analogous to

those discussed above concerning

general allocations to NOX budget units.

The EPA proposes to allocate NOX

allowances to opt-in units on a year-byyear basis to ensure that shifts in

utilization from these units to other

units not covered under the cap do not

result in any significant increases in

overall NOX emissions. Such increases

in emissions may occur if units outside

the cap increase their utilization (and

emissions) while NOX allowances

remain under the cap from an opt-in

unit that reduces its utilization. The

year-by-year allocation regime limits

this potential problem while still

maintaining continuing economic

benefits for a unit to opt in because each

of the future year allocations are

calculated based on the unit’s baseline

emissions rate multiplied by the lesser

of the baseline heat input or the

previous year’s utilization. By reducing

a unit’s actual emission rate below the

baseline emission rate, an opt-in unit

would continue to earn NOX allowances

to sell in the market in future years as

long as they continued to operate at the

same level. The EPA solicits comment

on the appropriateness of the year-byyear allocations to account for the

potential shifts in utilization for the

different types of possible opt-in units

including units that serve electricity

generators as well as other types of

industrial units.

c. Units Sharing Stacks or Fuel Pipe

Headers With NOX Budget Units.

Today’s proposal does not include

special or simplified opt-in provisions

for non-NOX budget units that share a

common stack or common fuel pipe

header with a NOX budget unit.

Allowing these units to participate in

the trading program may streamline the

monitoring and reporting requirements

for the NOX budget units. For example,

if a non-NOX budget unit sharing a

common stack with a NOX budget unit

is opted in to the trading program, it

may no longer be necessary to apportion

common stack emissions between two

units. The NOX AAR may simply elect

the percentage of NOX allowances to be

deducted for each unit, provided that

the total number deducted covers the

common stack emissions. The EPA

solicits comment on the desirability and

method of opting in such units.

d. Withdrawal and Termination of

Opt-In Units. The proposed trading rule

addresses how an opt-in unit may

withdraw from the trading program. An

opt-in unit may withdraw from the NOX

Budget Program at any time, but a

request to withdraw may be effective

only on a date specified by the NOX

AAR that is before or after a control

period. The EPA believes that the

administrative burden for a permitting

authority in processing a withdrawal

effective during a control period,

particularly in ascertaining the

disposition of NOX allowances and in

determining compliance for a partial

control period, is sufficient to warrant

the prohibition of an effective date of

withdrawal during a control period.

Further, an opt-in source could seek to

withdraw during a control period

because the opt-in source projects that

it will not hold enough NOX allowances

to account for its NOX emissions for that

control period. Under such a scenario,

allowing the unit to ‘‘opt out’’ of the

program during a control period could

easily result in higher NOX emissions,

since an opt-in unit could emit enough

NOX to use up its NOX allowance

allocation for the control period prior to

the end of that control period, withdraw

from the program, and continue to emit

NOX after withdrawal during the control

period. Such emissions would not be

accounted for with the requisite

surrender of NOX allowances required

under the NOX Budget Program and

could occur outside of a State’s overall

budget for NOX.

If a NOX budget opt-in unit becomes

a NOX budget unit under 40 CFR 96.4,

the opt-in permit is terminated. This

change in status for an opt-in unit could

occur as a result of a modification,

reconstruction, or repowering that may

take place at the unit. An opt-in unit

that becomes a NOX budget unit under

40 CFR 96.4 is required to notify the

permitting authority within 30 days of

the change in status of the opt-in unit.

The permitting authority revises the optin permit to reflect the NOX budget

permit content requirements of 40 CFR

96.23 effective as of the date of the
25942 Federal Register / Vol. 63, No. 90 / Monday, May 11, 1998 / Proposed Rules

change in status. The NOX allowances

are deducted or allocated as necessary

to ensure that the appropriate number of

allowances are allocated to the unit

consistent with 40 CFR part 96 subpart

E of the proposed trading rule for each

partial or full control period after the

effective date of the change in status. In

addition to the potential of an opt-in

unit changing its status and becoming a

NOX budget unit under 40 CFR 96.4, it

is also possible that an opt-in unit may

become subject to the major new source

review (NSR) requirements under

section 173 of the Act by making a

physical change or a change in the

method of operation. In this case,

triggering nonattainment NSR may also

terminate an opt-in permit as discussed

above. In Section C.1.c.v above, EPA

seeks comment on treating all sources

that are subject to major nonattainment

NSR and that are of the same type of

source included in the proposed core

applicability as NOX budget units.

11. Program Audits

The EPA would publish a report

annually, commencing after the first

year of compliance, that would contain,

for each NOX budget unit, the control

period NOX emissions and the number

of NOX allowances deducted for all

reasons. This would be done in order for

States to track emissions and NOX

allowance transaction activity in

neighboring and upwind States. The

proposed transport rulemaking has

requirements for reporting of additional

data to determine compliance for

affected States. The EPA would also

publish a report beginning in 2007 and

every five years thereafter to assess the

level of activity and/or emissions

shifting from sources included in the

NOX Budget Program to sources not

included. An assessment of opt-in

sources (e.g., how many, from what

sector, source size, duration of

participation in program) would also be

included in this periodic report.

12. Administration of Program

The administration of this program

would be somewhat different from the

administration of a typical State

program. This is both because of the

trading aspects of the program and

because of the regional nature of the

trading program. In order for the market

forces underlying the trading program to

work, the sources that participate in the

trading program must have confidence

in the market. This confidence stems

from a number of factors including: a

belief that all of the sources included in

the program are following the same set

of rules, and a belief that trades can be

made easily, quickly and with a great

deal of confidence that they will not be

altered or denied. Several things can

help to foster these beliefs and thus a

confidence in the market. The first is to

start with a consistent set of rules. This

can be done by developing a model rule

and having all States and sources that

participate in the trading program abide

by the ground rules set forth in the

model rule. The second is to implement

those rules in a consistent and efficient

manner. Because of the multi-state

nature of the program, it would be

difficult for any individual State to do

that by itself. Therefore, EPA is

proposing that this program be

implemented jointly by EPA and the

States that choose to participate in the

program. As part of this joint

implementation, States would have

specific roles, EPA would have specific

roles, and there would be roles that

States and EPA would perform jointly.

States would be responsible for

developing and promulgating rules

consistent with the model rule and for

submitting those rules as part of the SIP.

States would also be responsible for

identifying sources subject to the rule,

issuing new or revised permits as

appropriate, and determining NOX

allowance allocations. In addition, they

would be responsible for receiving,

reviewing and approving most

monitoring plans and monitoring

certification applications, observing

monitor certification and ongoing

quality assurance testing and

performing audits. The final primary

area of State responsibility would be

enforcement of the trading program. If

violations occur, the State would take

the lead in pursuing enforcement action.

However, once the rules are approved as

part of the SIP, they would become

federally enforceable, and EPA could

also take enforcement action.

The EPA would have two primary

roles in administration of the program.

The first role would be EPA’s traditional

role in the approval and oversight of the

SIP. The second would be a more

unique role for EPA, in which EPA

would administer significant portions of

the program.

In EPA’s traditional role in the SIP

process, EPA would be responsible for

taking action to approve or disapprove

the SIP revision once it was submitted

to EPA. Once the SIP revision was

approved, EPA would play an oversight

role in ensuring that the SIP was

completely implemented. This oversight

role might include audits of the State

program, or taking enforcement action,

if EPA believed that sources were

violating the SIP.

In EPA’s more unique role as

administrator of portions of the

program, EPA would run both the

emissions tracking system (ETS) and the

NATS. ETS is the system that units

would use to report their emissions data

and that EPA would then use to verify

total emissions for the control season.

The EPA would use the same system

that it is currently using to track

emissions data from the Acid Rain

Program and that it will soon be using

to track emissions data from the OTC

NOX Budget Program. There are a

number of advantages to the sources,

States, and EPA to using this existing

system. Since many units are already

reporting to the system for purposes of

the Acid Rain Program and more units

will soon be reporting to the system for

purposes of the OTC NOX Budget

Program, using this existing system will

represent little change for many units

and EPA. This will help to reduce

administrative costs for both units and

EPA and will help to minimize startup

problems associated with a new

program. It also means that each State

will not need to develop, maintain and

operate such a system.

In addition to receiving the emissions

data, quality assuring it, and providing

reports to both States and units about

the emissions data, EPA would have

several other responsibilities as the

administrator of ETS. The EPA would

be involved in approval of any petitions

for alternatives to the allowable

monitoring methods. The EPA would

also be involved in providing units and

States assistance in using ETS. This

assistance may include: Answering

individual questions from units and

States, providing guidance documents

and training for units and States, and

providing software to assist in the

submittal of emissions data.

As the administrator of NATS, EPA

would be responsible for receiving

applications for NOX AARs, tracking all

official transfers of NOX allowances, and

using the end of control season

emissions data and NOX allowance data

to determine compliance for the control

season. In order for EPA to play this

role, each State would have to provide

EPA with its NOX allowance allocations

consistent with a prescribed schedule

and format. The NOX AARs for

individual sources would have to

provide EPA with information about all

official NOX allowance transfers in a

prescribed format. The NOX AAR’s

would also have to provide EPA with an

end of control season compliance

certification. At the end of the control

season, EPA would use all of this data

to determine how many NOX

allowances should be deducted from

each unit’s compliance account or each

source’s overdraft account. In the event
Federal Register / Vol. 63, No. 90 / Monday, May 11, 1998 / Proposed Rules 25943

that there were not enough NOX

allowances to cover a unit’s emissions

for a control period, EPA would notify

the State and would automatically

deduct NOX allowances for the next

year’s control period according to the

emissions offset provisions set forth in

the proposed trading rule.

The main joint role that EPA and

States would have is for the approval of

alternatives to the allowable monitoring

methods. This role is more fully

discussed in Section V.C.9 of the

preamble on monitoring.

D. SIP Approvability

The EPA’s proposed ozone transport

rulemaking set forth the general

elements that a SIP needed to include

(see 62 FR 60364–71). These criteria are

more fully explained in Section IV.A of

this supplemental proposal. One of the

components of an approvable SIP is that

it include fully adopted State rules for

the regional transport strategy with

compliance dates. One possible control

strategy that a State might choose would

be to implement this NOX Budget

Trading Rule (40 CFR part 96). If a State

chooses to implement the NOX Budget

Trading Rule, the proposed ozone

transport rulemaking explains that the

trading rule will incorporate all

necessary SIP criteria into the program

design. In general, today’s proposed

trading rule meets the necessary SIP

criteria. However, Section IV.A

describes two criteria that a SIP must

meet for EPA to approve the NOX

Budget Trading Rule portion of the SIP

(see Section IV.A.3 for further

discussion).

E. OTC Integration

Twelve of the thirteen OTC

jurisdictions have committed to the

implementation of a cap-and-trade

program in order to achieve region-wide

NOX emissions reductions starting in

1999 to help reduce ozone transport and

make progress toward attainment. Nine

of those twelve jurisdictions are also

included in the proposed ozone

transport rulemaking. The goals and

implementation strategy of the OTC

program are similar to those of the

proposed transport rule and today’s

proposed NOX Budget Trading Program.

However, there is a potential for conflict

between the OTC Program and today’s

proposal. The EPA was involved in the

development of the OTC Program and is

aware of the issues that the OTC States

faced in developing that program.

Taking into account the work that has

been done, EPA has tried to develop a

proposal that will minimize conflicts

between the two programs. Some

differences still exist concerning

applicability, allocations, banking and

the use of banked allowances, emissions

monitoring, and permitting. The

purpose of this Section is to identify

how EPA believes that these specific

issues can be resolved, so that the goals

of the OTC program can be achieved in

concert with today’s proposal. The EPA

believes that these differences can be

resolved as the OTC States undertake

rulemakings to implement Phase III

(beginning in 2003) of the OTC program.

1. Applicability

a. State Applicability. On a regional

level, the NOX Budget Trading Program

is applicable to any of the 23

jurisdictions identified in the proposed

transport rulemaking electing to

participate. Three of the OTC States

(Maine, New Hampshire, and Vermont),

however, are not among the 23

jurisdictions cited in the proposed

transport rulemaking. The OTC States

have requested EPA to consider how

these States may participate in the

trading program. The EPA sees, and

requests comment on, two options for

addressing these States. One option is to

exclude Maine, New Hampshire, and

Vermont from participation in the NOX

Budget Trading Program; the other is to

offer the States the opportunity to join

the trading program by complying with

the overall requirements of the proposed

transport rulemaking. The EPA proposes

the two alternative options and requests

comment on them.

Denying Maine, New Hampshire, and

Vermont the opportunity to participate

in the NOX Budget Trading Program can

be justified by their exclusion from the

proposed transport rulemaking. Based

on analysis of the entire 37 State OTAG

region, EPA proposed to determine that

only 23 jurisdictions are significant

contributors to a nonattainment or

maintenance problem in another State.

Since these three States were not among

the 23 jurisdictions covered by the

proposed transport rulemaking,

arguably they should not be permitted

to participate in the trading program

designed to help achieve mandated

reductions in the targeted States.

Excluding Maine, New Hampshire, and

Vermont from the trading program

would restrict the ability for sources in

these States to trade NOX allowances

with sources in other OTC States that

are included in the proposed transport

rulemaking and participating in today’s

proposed trading program. A second

option would be to allow Maine, New

Hampshire, and Vermont to participate

in the NOX Budget Trading Program by

voluntarily enrolling in the proposed

ozone transport rulemaking and

implementing the requirements therein.

This second option would assist with

the integration of the OTC program with

the NOX Budget Trading Program by

maintaining the ability for sources

located in Maine, New Hampshire, and

Vermont to trade NOX allowances with

sources located in the other

participating OTC States.

b. Source Applicability. The source

applicability criteria for today’s

proposed NOX Budget Trading Program

identifies a minimum, core group of

sources. These core sources are fossil

fuel-fired units (i.e., stationary boilers,

combustion turbines, and combined

cycle systems) serving electrical

generators greater than 25 megawatts

and other units not serving generators

and having a heat input greater than 250

mmBtu per hour. Beyond the core

sources, this proposal contains criteria

for States to include additional sources

in the trading program, as well as the

process for allowing individual units to

opt in.

The OTC program applies to a similar

universe: fossil fuel-fired boilers and

indirect heat exchangers of 250 mmBtu

or greater, electricity generating units of

15 megawatts or greater, and ‘‘opt-in’’

sources. The main difference in

applicability criteria between the OTC

program and today’s proposed NOX

Budget trading program is that the OTC

includes units between 15 and 25

megawatts. However, today’s proposal

allows States to include smaller sources

of the same type as those included in

the core group such as electrical

generating units between 15 and 25

megawatts, without affecting EPA’s

streamlined approval of the SIP as

described in Section V.D of this

preamble. This allows the OTC program

applicability provisions to be reasonably

compatible with those in the NOX

Budget Trading Program.

2. Allocations

Today’s proposal establishes NOX

allowances as the currency for the NOX

Budget Program, and recommends a

methodology for participating States to

allocate NOX allowances among NOX

budget sources. States are provided the

flexibility to deviate from the

recommendation, as long as the timing

requirements for completion of

allocations and submission of the

information to EPA for inclusion into

the NATS are met, the control periods

for which allowances are allocated are

the same, and total NOX allowances

allocated do not exceed the number of

tons that the State apportions to NOX

budget sources in the SIP.

The OTC provides States full

discretion to develop and adopt their

own allocation methodologies. The
25944 Federal Register / Vol. 63, No. 90 / Monday, May 11, 1998 / Proposed Rules

resulting allocation processes are in

some cases incompatible with EPA’s

software capabilities, beyond the scope

of EPA’s resources to administer, and

inconsistent with the efficient and

orderly functioning of a NOX allowance

market. This experience showed the

need for greater consistency among

States for the allocation process. As a

result, the OTC States would need to

revise their allocation methodologies for

Phase III of the OTC to be consistent

with the timing requirements of the

NOX Budget Trading Program. Since the

OTC is still discussing the

implementation of Phase III, EPA

believes that the schedule for this

proposal provides an opportunity to

develop allocation plans that meet the

timing requirements in today’s proposed

trading program. Each OTC State would

still be able to determine the specific

allocation to each source provided the

total number of allowances allocated

did not exceed the trading program

budget.

3. Emissions Banking

The OTC program provides for the

banking of early reductions in 1997 and

1998 and of excess Phase II NOX

allowances in 1999 through 2002.

Furthermore, the OTC program includes

the use of a flow control mechanism to

manage the use of banked allowances as

described under Section V.C.7 of this

preamble and an audit to assess the

program’s performance. Today’s

proposal solicits comments on four

banking options that are discussed

under the banking Section of this

preamble. The EPA requests comments

on how the OTC banking provisions

may be integrated with the banking

options under the proposed NOX Budget

Trading Program.

4. Emissions Monitoring and Reporting

The monitoring and reporting

requirements in the proposed NOX

Budget Trading Program are based on

the requirements in proposed revisions

to 40 CFR part 75, the monitoring and

reporting regulations under the Acid

Rain Program. The monitoring and

reporting requirements in the OTC’s

NOX Budget Program are based on the

current version of 40 CFR part 75 and

on additional guidance that was

developed in a collaborative process

among States, sources, and EPA. This

additional guidance sets forth

requirements for reporting NOX mass

emissions which are not currently set

forth in 40 CFR part 75 and provides

some additional flexibilities for sources

not subject to the Acid Rain Program.

For sources that are subject to both the

Acid Rain Program and the OTC NOX

Budget Program, use of the revised 40

CFR part 75 would require few changes

to address the NOX mass monitoring

and reporting requirements in this

proposal. However, for some sources

that are only subject to the OTC NOX

Budget Program, the use of the revised

40 CFR part 75 in the proposal may

require some changes.

The most significant change under the

proposed NOX Budget Trading Program

would be that all units that burn coal or

other solid fuels would be required to

use a flow monitor and a diluent

monitor to measure heat input. Under

the OTC NOX Budget Program, these

units currently have two options for

monitoring heat input: the first option is

to use a flow monitor and a diluent

monitor, and the second is to petition

the State to use an alternative heat input

methodology. There are two main

reasons that EPA is proposing to limit

the options for monitoring heat input for

these types of units. First, EPA believes

that in order to ensure fairness and to

ensure that the emissions reductions

required by this program are realized, it

is important to have accurate and

consistent monitoring across all of the

sources. To date, no source under the

OTC NOX Budget Program has

completed any testing to demonstrate

that the alternatives are as consistent

and accurate as the flow monitoring

methodology. Second, EPA does not

believe that there are significant cost

savings associated with allowing the

alternatives. In order to demonstrate

that the alternative is as consistent and

accurate as the flow monitoring

methodology, the source is required to

do initial certification testing and

ongoing quality assurance testing very

similar to the testing required for the

use of flow monitoring methodology.

The capital costs associated with setting

up platforms and ladders so that this

testing can be performed is one of the

most significant capital costs associated

with the flow monitor methodology, but

this cost would also have to be incurred

in order to perform testing on the

alternative methodology. Similarly,

some of the most significant costs

associated with the ongoing use of the

flow monitor methodology are ongoing

quality assurance and data reporting.

Performing similar quality assurance

and data reporting is also a requirement

for any alternative methodology. For

these reasons, EPA believes the costs

would be similar. In addition, if the

alternatives are allowed, there would be

an additional administrative burden

placed on both States and sources in

preparing and reviewing applications

for alternative methodologies.

In addition to the specific

requirement to use flow monitors for

coal-fired facilities, the proposed

revisions to 40 CFR part 75 change some

of the ongoing quality assurance tests

for flow monitors. The number of levels

at which flow relative accuracy test

audits (RATAs) have to be performed is

reduced, but an additional quarterly

quality assurance of the flow monitors

has been added. The EPA believes that

the combined effect of these changes

reduces the overall cost of flow

monitoring, while at the same time

improving the quality of the data.

Another significant change between

the OTC NOX Budget Program and the

proposed NOX Budget Trading Program

would be in the options allowed for low

mass emitting units, or peaking units,

that burn oil and/or gas. The OTC NOX

Budget Program offers a number of

different options for these units, in

addition to the CEM options that are

allowed for all sources in the program.

While these different options provide

more flexibility, they also create more

confusion and complexity for smaller

sources. The EPA believes that by

proposing fewer options, and

simplifying these allowable options as

much as possible, both cost and

confusion for smaller sources can be

minimized. The two non-CEM options

that the proposed revisions to 40 CFR

part 75 will allow for smaller sources

are the use of a default emission rate

based on unit type and fuel burned, and

the use of source testing to determine

unit specific NOX emission rate versus

load curves. The use of default emission

rates is proposed to be limited to units

that have actual emissions and projected

emissions using such default emission

rates of less than 25 tons per year. The

use of the unit specific NOX emission

rate versus load curves is proposed to be

limited to units that qualify as peaking

units (a unit that has an average

capacity of no more than 10.0 percent

for three years, with a maximum

capacity of no more than 20.0 percent in

any one of those years.)

Most of the other changes in the

proposed revisions to 40 CFR part 75

that would affect OTC NOX Budget

Trading Program sources are designed to

reduce monitoring costs and provide

additional flexibilities. These include: a

reduction in fuel sampling for units that

use fuel sampling and analysis to

determine heat input; more flexibility

for the scheduling of quality assurance

testing to accommodate unexpected unit

outages; and an option to reduce the

amount of missing data that must be

reported during periods of monitor

recertification. More information on all

of the proposed revisions to 40 CFR part
Federal Register / Vol. 63, No. 90 / Monday, May 11, 1998 / Proposed Rules 25945

75 can be found in the proposal for that

rule (notice entitled ‘‘Acid Rain

Program; Continuous Emission

Monitoring Revisions’’ that will be

published in the Federal Register in the

near future); comments on them should

be submitted in that separate

rulemaking.

5. Permitting

The OTC program does not explicitly

require permits that are issued or

modified for use under the OTC

program to be federally enforceable. The

proposed NOX Budget Trading Rule

requires federally enforceable permits.

The EPA’s rationale for requiring

federally enforceable permits is further

explained in Section V.C.3 of this

preamble. This would potentially

require the OTC States to amend the

permitting provisions in the OTC

program.

F. New Source Review

Under section 173 of the CAA, new

and modified major sources located in

nonattainment areas must offset their

new emissions. The EPA believes that

this requirement can be met through a

source’s participation in the NOX

Budget Trading Program defined in

today’s proposed rule. Simply put, in a

system where the level of emissions

cannot exceed an absolute mass

emissions cap, new sources of emissions

subject to the system must acquire

sufficient NOX allowances elsewhere in

the system to offset any new emissions.

Those sources from whom NOX

allowances are acquired must also hold

sufficient NOX allowances to cover their

emissions. Therefore, since the trading

program budget would not be increased

for sources seeking offsets, NOX

allowances which are acquired

necessarily come from actual emissions

decreases that take place from other

sources that are covered by the cap.

A key issue is how sources whose

emissions increases are subject to the

major NSR offset requirements may

become participants in the trading

program. All new units meeting the

proposed applicability criteria, and all

emissions increases at existing units

meeting these criteria, would be subject

to the NOX Budget Trading Rule and,

therefore, would be participants in the

trading program. However, sources in

need of NSR offsets but which do not

meet the proposed applicability criteria

may wish to participate in the trading

program so as to satisfy their NSR offset

requirement. The EPA notes that today’s

proposed rule makes no specific

provision for the inclusion of these

types of sources. Since EPA believes

there may be significant benefits to

integrating any new source review

requirements with the NOX Budget

Trading Program, inclusion in the

trading program of new sources that do

not meet the proposed applicability

criteria may well be helpful to both

those sources and States that are

concerned about finding offsets for new

sources. The EPA solicits comments on

allowing the opt in of new and modified

sources, not otherwise subject to the

program, in order to satisfy the section

173 offset provisions through

participation in the trading program.

Commenters should consider how these

sources would be integrated into the

trading program in a simple and

straightforward manner which would

not compromise any of the program’s

goals or requirements. For example,

EPA expects that any source opting into

the trading program would have to meet

the permitting, monitoring, and

accountability requirements applicable

to core sources. At this time, EPA also

solicits recommendations on: (1) How

the section 173(c)(1) requirements

pertaining to the geographic location of

offsets can be met under the NOX

Budget Trading Program and (2) how to

reconcile the seasonal nature of the

proposed rule with the NSR

requirements that the total annual

tonnage of new emissions increases

must be offset.

G. End Use Energy Efficiency and

Renewable Energy

1. Background

This Section discusses the potential

for a provision within a State’s NOX

Budget Trading Rule to recognize and

encourage the contribution that energy

efficiency and renewables can make in

meeting the NOX budget. The December

workshop with State, industry and nongovernmental organization

representatives included a discussion of

a possible role for energy efficiency and

renewables. As stated in the December

workshop, energy efficiency and

renewables can be important

components of an effective NOX

reduction strategy. Greater deployment

of energy efficiency and renewables

technologies cannot only be a costeffective means of preventing emissions

of NOX. It can also be a cost-effective

way of preventing emissions of

greenhouse gases, such as carbon

dioxide (CO2), and toxic substances,

such as mercury.

There is a large potential for greater

energy efficiency improvements that

reduce energy demand. In addition,

renewable resources that reduce

demand at the consumer level are

available, including technologies that

generate electricity, such as rooftop

photovoltaics, and technologies that

reduce electricity demand such as solar

hot water heaters. Greater penetration of

energy efficiency and distributed

renewable resources in the marketplace

can save companies and individuals

money and promote economic growth,

thus reducing the economic cost of

compliance with environmental

requirements. These savings can be

passed on to consumers through lower

electricity rates.

The EPA has examined the potential

for energy efficiency and renewables in

the SIP call region. The most recent

information on this potential comes

from the Department of Energy’s (DOE’s)

‘‘5-lab study,’’ which quantifies the

potential for energy efficiency and

renewables to reduce carbon emissions

in the U.S. via two scenarios. The first

is the study’s ‘‘Efficiency’’ case which

consists of the potential for costeffective energy efficiency and

renewables technologies to penetrate the

market given an invigorated promotion

effort for greater market transformation.

The second scenario is the ‘‘High

Efficiency’’ case, which demonstrates

the potential for emissions reductions

from energy efficiency and renewables

measures that are optimistic, but

feasible to undertake. Both the DOE

study and the findings and results from

similar analyses that have been

conducted in the last several years in

different States or groups of States

within the proposed ozone transport

rulemaking region show substantial

potential for NOX reductions and

ancillary benefits from greater adoption

of energy efficiency and renewable

technologies. According to an analysis

based on the DOE 5-lab study,

approximately 1,700 TBtu of energy can

be saved by 2007, resulting in over

100,000 tons of avoided seasonal NOX

emissions in the SIP call region if the

area achieves the increased rate of

energy efficiency improvement outlined

in the ‘‘Efficiency’’ case. These

potentials increase to over 3,000 TBtu of

energy saved and over 200,000 tons of

avoided seasonal NOX emissions (or 13

percent of the total tons of reductions

needed) under the 5-lab ‘‘High

Efficiency’’ case. The associated carbon

emissions reductions are nearly 30

million metric tons of carbon equivalent

(MMTCE) by 2007 for the ‘‘Efficiency’’

case, and over 50 MMTCE for the ‘‘High

Efficiency’’ case.

In a recent study of energy efficiency

opportunities in the mid-Atlantic States

region (including New York, New Jersey

and Pennsylvania), the American

Council for an Energy-Efficient

Economy (ACEEE) concluded that over
25946 Federal Register / Vol. 63, No. 90 / Monday, May 11, 1998 / Proposed Rules

2,800 TBtu of energy could be saved in

this area by 2010 under their aggressive

efficiency scenario. This translates into

over 200,000 tons of seasonal NOX

reduced by 2007, and nearly 160 million

metric tons (MMT) of carbon emissions

avoided. Enhanced deployment of

energy efficiency technologies and

distributed renewable resources,

therefore, may be an important policy

tool for States to consider in achieving

multiple environmental objectives.

There are substantial economic

benefits and compliance cost

implications for using energy efficiency

as a NOX reduction strategy in the

proposed ozone transport rulemaking

region. The economic benefits of

achieving the 5-lab study’s ‘‘Efficiency’’

case level of improvement include the

potential for creating a net increase of

over 80,000 jobs. For the ‘‘High

Efficiency’’ case, over 160,000 new jobs

would be created. The mid-Atlantic

study shows a net increase of

approximately 16,000 new jobs created

in the region, with a corresponding

increase in gross State product (GSP) of

over $60 billion by achieving the

efficiency potential outlined in the

study. Taking advantage of all of the

energy efficiency and renewables

potential in the SIP call region prior to

applying other NOX control methods,

such as selective catalytic reduction

(SCR) or selective non-catalytic

reduction (SNCR), can lower the overall

compliance costs of meeting the NOX

budget as well as reduce overall societal

costs. The EPA’s initial analyses show

that compliance costs can be reduced in

2005 by nearly $150 million through

accelerated adoption of energy

efficiency and renewables consistent

with the 5-lab study in the proposed

ozone transport rulemaking region.

2. Energy Efficiency and Renewables

Set-Aside Options

The EPA recognizes and has

performed analyses that demonstrate the

benefits of aggressive adoption of energy

efficiency and renewables technologies

as a NOX reduction strategy in the

proposed NOX Budget Trading Program

for the proposed ozone transport

rulemaking region. However, EPA is not

proposing a specific approach for an

energy efficiency and renewables setaside for NOX Budget Trading Program

in this action.

During the December workshop and

in the discussion paper that was

distributed afterward, EPA stated that

an energy efficiency and renewables setaside approach put forward by the

Agency should meet three important

goals: (1) reduce the total economic cost

of meeting the proposed NOX budget, (2)

promote energy efficiency and

renewables as effective NOX and

pollutant-reducing strategies through

the accelerated adoption of such

practices and technologies, and (3)

reduce future CO2-related liabilities by

recognizing the positive impacts of

energy efficiency and renewables on

carbon emissions. In addition, EPA

stressed that two key principles should

guide the design of its approach for a

set-aside program: (1) A set-aside

program should encourage actions that

increase efficiency that would not

otherwise occur without the program,

and (2) the set-aside program should

maintain the integrity of the NOX cap.

The EPA noted in its December

workshop discussion paper that the

difficulties in designing an approach

consistent with our objectives of

reducing cost and meeting the goals and

principles above are not trivial. At this

time, EPA does not have adequate

information to propose an approach that

will accomplish the goals and meet the

Agency’s purposes, while adhering to

the principles and addressing the design

issues outlined at the December

workshop.

The EPA is not including a proposal

in this notice to include an energy

efficiency and renewables set-aside in

the NOX Budget Trading Program. The

EPA continues to consider whether and

how to develop an approach to include

energy efficiency and renewables in the

NOX Budget Trading Program. As part of

this action, EPA today requests that

interested parties submit information

addressing the design issues and

questions that require further

investigation which are outlined below.

Should EPA conclude in the future that

there is adequate information to design

an approach for including an energy

efficiency and renewables set-aside to

meet its purposes, EPA will either issue

a proposal or guidance as appropriate.

While EPA continues to examine the

possibility of designing an approach for

a set-aside, EPA encourages States to

consider including energy efficiency

and renewables in their State NOX

Budget Trading programs.

• Issue (1) Rewarding Efficiency

Improvements Above ‘‘Business as

Usual’’

In developing an approach for energy

efficiency and renewables in the NOX

Budget Trading Program, EPA believes

it is important that the system

encourage actions that increase the

penetration of energy efficiency and

renewables improvements beyond the

normal rate at which they are currently

and continuously incorporated into all

sectors of the U.S. economy. Some

remarks received in response to the

discussion paper were of the opinion

that it is unnecessary to be concerned

with business-as-usual projects (or

‘‘anyway’’ tons or ‘‘anyway’’ projects),

specifically because the respondents

believe that the restructuring of the

electric utility industry will result in the

decline of demand side management

(DSM) programs and reduce the rate of

business-as-usual energy efficiency and

renewables adoption to below a

meaningful level. However, because

energy efficiency projects often yield

very attractive internal rates of return,

many above 35 percent, and because

there are many public information

programs and private businesses aiming

at getting more energy efficient and

renewables products and choices into

the market, there is likely to be a

continuing level of energy efficiency

improvement in the U.S. economy.

Allocating NOX allowances to existing,

mandated and expected energy

efficiency and renewables measures

means that fewer allowances will be

available to encourage incremental

projects. The issue is in determining

how to differentiate between the various

types of measures and, particularly in

future years, determining what types of

measures were likely to have happened

without the set-aside program. In regard

to the amount of ‘‘business-as-usual’’

energy improvement due to energy

efficiency and renewables, EPA requests

the following information:

Question 1. How do States determine

the amount of ‘‘business-as-usual’’

energy efficiency and renewables

occurring across all sectors of the

economy?

Question 2. What information do

States and other entities have about the

amounts and types of energy efficiency

and renewables that have been

occurring over the last 3–5 years?

The EPA suggested three options for

determining projects eligible for setaside NOX allowances in its December

workshop discussion paper. One option

is to limit the reward of ‘‘business-asusual’’ projects may be to require that

projects attain a sizable efficiency

improvement, over and above a set

minimum. This will require the

development of a set of average energy

improvement metrics for the residential,

commercial and industrial sectors. As

an example, projects for efficiency in

the commercial building sector would

be compared to a target set below the

average energy use per square foot that

achieves a particular and higher level of

efficiency than that of ‘‘business as

usual’’ in that sector. Only projects that

meet or exceed the target would be

eligible to be awarded allowances, and
Federal Register / Vol. 63, No. 90 / Monday, May 11, 1998 / Proposed Rules 25947

the size of the award would be based on

the increment of improvement between

the ‘‘business as usual’’ average and the

achievement or exceedance of the target.

Two other options involve varying the

length of the efficiency reward for

different types of energy efficiency

improvement measures, or restricting

the number of NOX allowances available

to certain types of improvements. Under

the second approach, certain types of

energy efficiency improvements that

have already been implemented or are

likely to be implemented without an

additional incentive (e.g., regulatorily

mandated improvements unless

implemented early, or energy efficiency

improvements of products that bring

them up to the industry average) would

be allocated a shorter stream of

allowances, while new and innovative

energy efficiency improvements

(incremental projects above ‘‘businessas-usual’’) would be allocated a longer

stream of NOX allowances. Under the

third approach, the number of NOX

allowances allocated to energy

efficiency improvements likely to occur

anyway is restricted to some portion

(e.g., 50 percent) of the full number of

NOX allowances they qualify for given

the actual or expected load reduction.

Of the three options, the first seems to

offer the best possibility for limiting

rewards for energy efficiency

improvements that would have occurred

anyway. Options two and three would

allocate a potentially smaller portion of

NOX allowances to projects that have

already been implemented, are

mandated, or are deemed to belong to a

classification of improvements judged to

be those likely to occur anyway. Either

of these latter two approaches is

difficult because it requires that a State

be able to differentiate between those

measures that would have been

implemented anyway versus other types

of energy efficiency improvements.

Option one would require that projects

attain a sizable efficiency improvement,

over and above a set minimum. This

would require the development of a set

of energy improvement metrics for the

residential, commercial and industrial

sectors to use to distinguish baseline

from accelerated or enlarged adoption of

energy efficiency and renewables. One

possibility for energy efficiency projects

under this option would be to develop

a set of energy use or intensity

benchmarks that these projects would

be required to meet or exceed in order

to be eligible.

The EPA could use information from

its own energy efficiency programs,

such as Energy Star Buildings and

Energy Star Homes, as a starting point

for developing benchmarks in the

residential and commercial buildings

sectors. For example, in its Energy Star

Homes program, home builders agree to

construct new homes that will be 30

percent more energy efficient than the

Model Energy Code (MEC). The EPA

could establish the ‘‘30 percent better

than MEC’’ as the benchmark that must

be attained for applicants wishing to

receive set-aside NOX allowances based

on new home developments that are

more energy efficient. The applicant

would have to first demonstrate that the

homes built meet this benchmark, and

then could be awarded NOX allowances

based on the improvement that reaching

the benchmark represents in that sector.

In considering the development of

benchmarks to limit the rewarding of

‘‘business-as-usual’’ projects, EPA

requests the following information:

Question 3. Do States and potential

applicants for energy efficiency and

renewables NOX allowances have

sufficient information about energy

improvement metrics (e.g., energy use

per square foot, MEC) or can they gather

sufficient information about upgrade

projects in order to be able to compare

the results of these projects with a

benchmark developed for that category

(residential, commercial or industrial) of

upgrade?

Question 4. If so, specifically what

types of energy improvement

measurements and information about

upgrade projects are recorded or

gathered by States and/or potential

applicants for energy efficiency and

renewables upgrades or projects?

Question 5. In addition to Energy Star

Buildings and Energy Star Homes what

other options are there for developing

benchmarks in the residential and

commercial buildings sectors?

Question 6. What kinds of

benchmarks could be developed for

industrial sector energy efficiency and

renewables improvements, and how

could they be developed? Since

industries have both process and nonprocess energy use, how could

benchmarks be developed for process

(e.g., motors, compressed air, fans) and

non-process (facility lighting and

HVAC) efficiency measures in the

industrial sector?

Question 7. In order to be able to use

benchmarks for industrial sector energy

efficiency it is necessary to separate the

facility’s non-process energy use from

its process-related energy use. What

methods might be used for

distinguishing between an industrial

facility’s non-process energy use from

its process energy use?

• Issue (2) Appropriate Size of the SetAside Allowance Pool

The EPA indicated in the December

workshop discussion paper that the

energy efficiency and renewables

allowance pool within the budget for

the NOX Budget Trading Program

should be set at an amount large enough

to maximize the opportunities to

promote energy efficiency and

renewables projects, but not so large as

to overstate the efficiency potential so

that there are excess NOX allowances

that go unallocated. As pool size is

related to the rewarding ‘‘business-asusual’’ issue, EPA listed two alternatives

in the December workshop discussion

paper: (1) Limit the size of the pool and

allocate NOX allowances based on

criteria that would minimize their

allocation to ‘‘business-as-usual’’

projects, or (2) establish a larger pool so

that there is room for both ‘‘business-asusual’’ projects as well as incremental

energy efficiency projects being

undertaken. Using three different

methods and the projections for energy

efficiency potential from the 5-lab

study, EPA showed that a set-aside pool

in the range of 5–20 percent of the total

electricity NOX budget for a State or

across the region could be considered

Note: these figures do not include a portion

of the nonutility boiler NOX budget.

The EPA received remarks indicating

that a set-aside pool should be not less

than 20 percent to allow for the full

potential of both energy efficiency and

renewables projects. Another

recommendation made to EPA is that no

specific pool size should be set within

the budget for the NOX Budget Trading

Program. Rather, a State could opt to

take all proposals for efficiency and

renewables ‘‘off-the-top’’ of the

allocation pool, and allocate the

remainder to NOX Budget units. Other

respondents to the December discussion

paper remarked that an ‘‘off-the-top’’

scheme would allow too little certainty

for NOX Budget units in planning for

how to meet the NOX cap. With regard

to pool size, EPA requests the following

information:

Question 8. What is a reasonable

estimate for a pool size within the

budget for the NOX Budget Trading

Program to award incremental energy

efficiency projects that would not be

undertaken without the availability of

set-aside NOX allowances?

Question 9. For States that may be

interested in an ‘‘off-the-top’’ allocation

method as opposed to a fixed percentage

set-aside for energy efficiency and

renewables projects, what allocation

mechanisms could be designed to

provide greater certainty to NOX budget
25948 Federal Register / Vol. 63, No. 90 / Monday, May 11, 1998 / Proposed Rules

units about the number of non-set-aside

NOX allowances for planning purposes

for the upcoming ozone season?

Once a pool size is determined, the

main issue of concern is how to

translate load reductions into

allowances. The December workshop

discussion paper outlines three basic

methods under consideration by EPA.

The first method would be to develop a

flat, region-wide, average NOX rate that

represents the average NOX emissions

reductions expected for a kWh reduced.

For this method, the rate could be based

on one of three NOX rates: (1) The

average NOX rate calculated by dividing

the total NOX emissions in an area on

an annual or seasonal basis by the total

fossil fuel generation in that area for the

same time period, expressed in lbs per

kWh State or region specific data; (2) an

average NOX rate calculated by

multiplying the proposed ozone

transport rulemaking NOX rate of 0.15

lbs per mmBtu by a system wide average

heat rate in Btu per kWh; or (3) an

average ‘‘marginal’’ NOX rate in lbs per

kWh representing the generation mix

most likely to be backed out on the

‘‘margin.’’ This marginal NOX rate is

calculated by dividing the difference in

NOX emissions in an uncapped scenario

between a reference or baseline amount

of electricity demand and a reduced

amount of demand (e.g., from energy

efficiency) by the amount of generation

(kWh) avoided due to the reduction in

energy demand.

The second method would be to

develop a regional or a State specific

NOX rate (average or marginal) in lbs/

kWh utilizing the IPM model which

would more accurately take into

account the generation mix in each State

and the power pools in which they

participate. Developing a regional or a

State specific rate would therefore take

into account the amount of NOX

reduction actually attributed to energy

efficiency in an uncapped NOX

environment. This method would likely

result in different NOX factors for each

State. The third method would be to

develop measure-specific marginal NOX

rates which would more accurately

represent the load shape associated with

particular energy efficiency measures

(i.e., commercial lighting or industrial

motors), or alternatively, NOX factors for

‘‘typical’’ residential, commercial and

industrial loads. This method would

therefore more accurately represent the

marginal generation units that would

likely be dispatched less.

The third method, if used to develop

measure-specific factors, could

potentially result in dozens of different

NOX rates and would likely be too

administratively burdensome. The first

and second methods may result in

either overstating or understating

emissions reductions for a particular

State. One respondent expressed a

preference for State-specific NOX factors

to be used in translating energy savings

into NOX reductions and the

corresponding NOX allowances.

Although State-by-State factors may

more accurately reflect the fuel mix of

a particular State, the use of different

rates and whether States consistently

use either an average or a marginal NOX

rate may impact the value of

allowances. If inconsistent methods are

used from one State to the next, then

one State’s efficiency allowances may be

construed to be of greater value than

another State’s. In order to evaluate the

three methods or an alternative to these

methods, EPA requests the following

information:

Question 10. What access do States or

end users have to information necessary

to obtain or calculate the average NOX

rate or the marginal NOX rate for their

State or power pool that may be used for

translating energy efficiency savings

into tons of NOX reductions?

Question 11. If a marginal NOX rate is

not available or calculable and an

average NOX rate is used, how would a

State or end user take into account the

type of different fossil fuel mix that the

efficiency savings is coming from? Is

this necessary to do?

• Issue (3) Eligibility of and Allocation

to Applicants and Projects

Although the scope of the set-aside

comprises appropriate end use energy

efficiency and distributed renewables

improvements, it is not intended to

limit the types of entities that may apply

for allowances based on completed end

use efficiency and renewables upgrades.

But keeping in mind EPA’s overall

objective of rewarding real reductions,

States may want to consider what types

of end users could implement efficiency

and renewables actions that best fit the

criteria of providing real reductions, and

focus their efforts on providing

incentive for those types of entities. The

EPA generally believes that entities that

would be provided this incentive

should be entities that would not

otherwise be holding allowances for the

purposes of being able to emit NOX.

Entities holding such NOX allowances

for these purposes have a direct

incentive to take actions that will lower

their need for NOX allowances or free

up NOX allowances for trading, and so

do not need an additional incentive.

With regard to the industrial sector, the

previous discussion and questions about

whether benchmarks can be determined

for improvements in the industrial

sector, and whether or not industrial

building energy use can be separated

from industrial process use may be

relevant to this discussion. Concerning

which end users it may be more or less

appropriate to award with NOX

allowances for reductions achieved

through greater energy efficiency and

use of renewable resources, EPA

requests the following information:

Question 12. In determining which

entities should be eligible to apply for

set-aside NOX allowances, is it

appropriate to limit eligibility to those

entities that would not otherwise be

holding NOX allowances for the

purposes of being able to emit NOX? If

not, why not?

In addition, for reasons of

administrative ease, it may be best for

entities to be required to meet a

minimum level of efficiency

improvement or NOX reduction. The

purpose of this requirement would be to

prevent the submission of large numbers

of applications for small amounts of

reductions, which may cause an

excessive administrative burden,

particularly in terms of time required for

processing and verification. For

example, applications for NOX

allowances of less than one ton of NOX

may be impractical because an

allowance is defined as one ton of NOX

emissions. It may be advisable to set a

higher threshold of NOX reductions,

such as five or ten tons or more, as a

minimum for application. This would

mean that an applicant for set-aside

NOX allowances would have to bring in

energy efficiency and renewables

projects that total no less than five or

ten tons of NOX reductions in order to

be considered for an award. Concerning

minimum thresholds for an award, EPA

requests the following information:

Question 13. How many applications

could a State reasonably review on an

annual basis for the set-aside without

causing an inordinate administrative

burden? What would be the incremental

administrative cost associated with the

application process for the set-aside?

There is also a concern about whether

or not the location of the applying entity

or where the energy efficiency or

renewables improvement is

implemented matters. The location of

the applying entity theoretically should

not matter, as long as the energy

efficiency and renewables

improvements result in NOX reductions

in the proposed ozone transport

rulemaking region.

However, there may be concern about

awarding allowances for end use

efficiency for projects in a State within

the ozone transport rulemaking region

where the load reduction or the majority
Federal Register / Vol. 63, No. 90 / Monday, May 11, 1998 / Proposed Rules 25949

of the load reduction is realized at an

electricity generating unit that is located

outside the NOX Budget Trading

Program region. If it is likely that the

end use efficiency will result in load

reductions occurring outside of the

proposed ozone transport rulemaking

region, then the amount of NOX

allowances to be awarded should

perhaps be adjusted to exclude the

reductions occurring outside the region.

This is in keeping with the principle of

maintaining the integrity of the NOX

budget. However, in order to do this,

States must be able to reasonably

estimate what amount of generation is

produced within the region versus that

which is being imported from outside

the area. In this regard, EPA requests the

following information:

Question 14. Will States be able to

reasonably estimate the amount of

generation produced within their States

and being imported from within the

proposed ozone transport rulemaking

region versus that which is being

imported from outside the region? How?

Question 15. Is it necessary to make

adjustments that would be to account

for reductions from energy efficiency or

renewables occurring outside the

proposed ozone transport rulemaking

region, and if so, what mechanisms are

there for doing so?

There is also the matter of whether

allowances for energy efficiency

improvements should be awarded for

actions that occur during the years prior

to the start date for the NOX Budget

Trading Program. Since the first year for

the trading program is 2003, it may be

possible to award NOX allowances for

energy efficiency and renewables

measures that are initiated and come on

line between the finalization of the

proposed NOX Budget Trading Rule and

the 2003 control period. This would

effectively give end users credit for early

actions taken to become more energy

efficient or to bring on new renewable

resources prior to the need for

additional/other controls to meet the

NOX budget. In considering giving

credit for early actions in the form of

NOX allowances from the set-aside pool,

EPA requests the following information:

Question 16. What amount or level of

incremental energy efficiency

improvements or renewable resources,

greater than ‘‘business-as-usual,’’ could/

may come on line if credit for early

action is given in the form of NOX

allowances from a set-aside that would

be available for trading once the trading

program begins?

Question 17. If no incremental

projects could come on line under an

early credit scheme, what are the

barriers preventing them?

Another topic of importance in this

area is the timing of applications for

projects to be considered for NOX

allowances and how entities should

apply. This concerns whether or not an

end user may be awarded energy

efficiency or renewables NOX

allowances prior to the implementation

of the improvement, or if an award can

only be made after the improvement is

in place and has demonstrated results.

While it would be unwise to award

allocations based on estimated savings

alone, greater incentive is provided to

potential projects if the applicant has

some degree of reasonable certainty of

receiving allowances for a project that is

being considered, provided that the

expected energy savings and NOX

reductions are achieved. One option is

to design a two-step application process,

where an applicant makes a submission

sufficiently prior to the first ozone

season for which that efficiency/

renewable project will be operational.

The State would review the project

proposal and pre-qualify that the project

is eligible for allowances. Then prior to

an ozone season, the applicant must

make a demonstration (e.g., of six

months or more) and verify whether the

appropriate efficiency standard(s) or

benchmark(s) has been met. If the

demonstration and verification

requirements are met, the State would

then issue the appropriate amount of an

allowance award. This option may

provide more certainty to the project

sponsor or applicant prior to

undertaking the project and may give

the State a better estimate of what level

of activity will occur for efficiency setaside allowances prior to the ozone

season. However, this option will

require two rounds of review for each

project or application and so may be

more administratively burdensome.

Another option would be to use a

single-step application process, where

applications would be made several

months ahead of an ozone season for

projects that are in place and can

demonstrate and verify reductions at

time of application. If the project meets

eligibility criteria and expected

reductions have occurred in line with

efficiency standard or benchmark, the

State would certify that applicant be

awarded allowances for the appropriate

ozone season(s). This second option

may be less burdensome, but it may be

more difficult to determine under this

method which projects could be

interpreted as ‘‘business-as-usual’’ types

of projects, since they will already have

been put in place without any guarantee

of receiving NOX allowances. In regard

to determining the process for a project

to apply for allowances, EPA requests

the following information:

Question 18. Which option for

reviewing and processing of

applications for energy efficiency and

renewables NOX allowances is

preferable and why? What is the

estimated administrative burden

associated with each option?

Question 19. Are there other options

for reviewing and processing

applications that offer a reasonable

degree of incentive and certainty to

applicants while minimizing the

administrative burden to States? What is

the estimated administrative burden?

The final matter in this issue area is

how to handle over or under

subscription of an energy efficiency and

renewables set-aside pool. Two options

outlined in EPA’s December workshop

discussion paper for dealing with

leftover NOX allowances in a given year

or period include: (1) Banking the

allowances to be used for potential

shortfalls in future years, or (2) retiring

them. The two options outlined in the

December workshop discussion paper

for dealing with shortfalls in NOX

allowances in a given year or period

include: (1) Deferring allocation of

allowances for later applicants in the

cycle until the following year, or (2)

setting aside a larger portion of

allowances from the NOX budget to

award end use energy efficiency and

renewables if shortfalls become a

chronic problem. One response to this

issue in the December workshop

discussion paper recommends not

setting a specific level of allowances in

the set-aside, but rather allocating all

NOX allowances necessary to cover the

eligible applications for efficiency and

renewables measures in a given period

first, then allocating the balance of

allowances to NOX budget units.

However, the EPA is concerned that this

method provides too little certainty to

NOX budget units in terms of being able

to plan for the number of allowances

they will need for a given ozone season

and to consider allowance trading.

Another suggestion received

recommends discounting the

allowances in the pool sufficiently to be

able to cover any over subscription in a

given period. This method would likely

result in differences in the amount of

allowances allocated to equivalent

projects that are submitted for

consideration in different periods. With

respect to under or over subscription of

the allowance pool, EPA requests the

following information:

Question 20. Which of the options

listed above for over subscription and

for under subscription of the set-aside
25950 Federal Register / Vol. 63, No. 90 / Monday, May 11, 1998 / Proposed Rules

pool is more administratively feasible

for a State, and why?

Question 21. What other options or

suggestions could be considered for

handling the over subscription or under

subscription of the set-aside pool?

• Issue (4) Persistence of Efficiency

Award

Because energy efficiency and

renewables measures result in

permanent improvements in energy use

and NOX reductions, it may be

appropriate to award energy efficiency

and renewables NOX allowances to

these projects for more than one year.

This provides a stream of allowances

and provides greater incentive for

incremental projects to be undertaken.

There are tradeoffs, however, between

the length of the stream of allowances

awarded to a project and the ability to

maintain sufficient availability of

allowances over time to provide

incentive for new projects that might

not otherwise be financially viable. A

shorter stream of energy efficiency NOX

allowances provides greater availability

of such NOX allowances over time to

reward new projects, but provides less

of an incentive (due to lower value) to

undertake such projects. A longer

stream provides more financial

incentive, but limits the availability of

allowances for future projects.

One respondent to the EPA December

workshop discussion paper suggested

that a five-year stream of allowances

should be sufficient to provide incentive

for new projects that might not

otherwise be financially viable. And

since the proposed NOX Budget Trading

Rule sets a five-year period as the

duration of the initial allowance

allocation to NOX budget units, EPA

believes that it is appropriate to set the

duration of energy efficiency awards to

five years. With regard to an appropriate

duration of award for energy efficiency

and renewables projects, EPA requests

the following information:

Question 22. How large an incentive

would a multi-year or a five-year stream

of allowances provide for new energy

efficiency or renewables projects that

might not occur otherwise?

Question 23. What kinds of

incremental projects might be

implemented as the result of a multiyear or five-year stream of NOX

allowances?

• Issue (5) Verification Requirements

and Procedures

In order to ensure that energy savings

are measured in a reliable and

consistent manner that provides valid

information about the NOX reductions

achieved, and that can be used in

translating these savings into their

associated NOX reductions for purposes

of awarding NOX allowances, a set-aside

program should have effective

verification requirements and

procedures.

Some respondents to the December

workshop discussion paper affirmed the

need for strong measurement and

verification protocols, but also stressed

that it is important that the methods

chosen should not be too complex. In

addition, it was suggested that the

methods and the degree of verification

fit the type of measure and the entity.

However, it is important that the

methods used for measurements are

reasonably consistent among all entities

participating in any set-aside programs

in the proposed ozone transport

rulemaking region. Further, some

respondents stated that the methods

used for awarding set-aside allowances

should be as accurate as the methods

used for monitoring NOX budget units

for their use of allowances.

There are three major existing energy

efficiency measurement protocols that

may be used to verify reductions for

purposes of a set-aside program: (1) The

Conservation Verification Protocol

(CVP) of the Acid Rain Program, (2) the

International Performance Measurement

and Verification Protocol (IPMVP)

developed by DOE with energy service

company (ESCO) input, and (3) New

Jersey’s Measurement Protocol for

Commercial, Industrial and Residential

Facilities (MPCIRF).

The CVP prescribes measurement

methods and confidence levels for

utilities to use in claiming sulfur

dioxide (SO2) allowances for savings

produced by DSM measures. Although

the CVP is comprehensive, this protocol

may not be appropriate to EPA’s

purposes in a NOX set-aside program

because the CVP was developed for

utilities, and the set-aside focuses on

demand side improvements. DOE

developed the IPMVP with ESCOs so

they could use them with their

customers to develop performance

contracts for efficiency measures. The

IPMVP however, has no regulatory

component, and some of the verification

methods it prescribes do not require the

actual measurement of energy savings.

The MPCIRF prescribes precise

monitoring and verification

methodologies by project type and also

provides procedures for developing new

monitoring and verification methods. In

order to determine what kinds of

reliable protocols exist or may need to

be developed, EPA requests the

following information:

Question 24. What is the degree of

reliability and validity of the

verification methods used in these

protocols? What is the administrative

burden associated with the use of one or

more of these protocols?

Question 25. Are there particular

parts or sections of one or more of these

protocols that work particularly well

and should be included in or used as a

model in developing a new

measurement and verification protocol?

Why?

Question 26. What other protocols

besides the CVP, the IPMVP and the

MPCIRF exist that States or other

entities have used to monitor and verify

energy efficiency projects?

Question 27. What is the degree of

reliability and validity of the

verification methods used in these

alternative protocols, and what is the

associated administrative burden?

Where the degree of reliability and

validity in the measurement of energy

efficiency and renewables

improvements is low, it is possible for

a tradeoff to be made between the level

of verification required (i.e., the

certainty of load reduction) and the

possibility that a given measure will not

result in the expected load reduction. A

discount factor or rate that is

commensurate with the level of

uncertainty of the reductions can be

applied to lower the total amount of

load reduction that would be awarded

allowances. The less stringent the

verification requirements, the higher the

discount rates should be set.

One option in developing alternative

verification/NOX allowance discounting

strategies is to determine the

uncertainty bounds associated with a

specific verification approach, and then

set the discount rate such that there is,

for example, a 90 or 95 percent

probability that all of the allowances

that would be awarded represent true

load reductions. For a more

conservative approach, the rate could be

set at a 99 percent probability level. One

variation on this option is to establish

several verification/discount strategies

rather than just one. These strategies

could range from a low verification/high

discount rate to a high verification/low

or no discount rate. With regard to

verification/allowance discounting

strategies, EPA requests the following

information:

Question 28. What are other options

to the verification/allowance

discounting strategies outlined above?

Question 29. What kinds of record

keeping are currently done by States or

others to monitor the progress and track

the results of energy efficiency and

renewables projects being done?

Question 30. Which option seems

most manageable for States? Why?
Federal Register / Vol. 63, No. 90 / Monday, May 11, 1998 / Proposed Rules 25951

20 In addition, if it is demonstrated that a boiler

with installed NOX control technology designed to

meet the applicable standard NOX limit cannot

meet that limit, the boiler may be assigned a less

stringent, alternative emission limitation under title

IV.

VI. Interaction with Title IV NOX Rule

On April 13, 1995, EPA promulgated

NOX emission rate limitations (in lb/

mmBtu) for certain types of coal-fired

utility boilers for the Acid Rain Program

under title IV of the Act (60 FR 18751,

April 13, 1995). The EPA set limits of

0.45 and 0.50 lb/mmBtu, respectively,

for tangentially fired boilers and dry

bottom, wall fired boilers (‘‘Group 1

boilers’’). On December 19, 1996, EPA

promulgated additional NOX emission

rate limitations for Phase II of the

program, i.e., revised limits for Group 1

boilers and new limits for cell burner,

cyclone, wet bottom, and vertically fired

boilers (‘‘Group 2 boilers’’) (61 FR

67112, December 19, 1996). In setting

the December 19, 1996 NOX limits, EPA

also promulgated a final rule provision

(which was to be included in 40 CFR

part 76 of the acid rain regulations) that

addressed the relationship between NOX

requirements under titles I and IV of the

CAA. As part of recent litigation in

which the December 19, 1996

regulations were upheld by the Court

(Appalachian Power v. U.S. EPA, No.

96–1497, slip op. (D.C. Cir., February

13, 1998)), EPA requested a remand,

which was granted by the Court, of 40

CFR 76.16 in order to provide additional

opportunity for public comment on the

provision. The EPA is therefore

including in today’s action a proposed

40 CFR 76.16 that is largely the same as

the remanded rule provision. Obviously,

in proposing a new 40 CFR 76.16, EPA

is not requesting comment on any

aspect of the December 19, 1996 final

rule, including any issues addressed by

the Court in Appalachian Power.

The EPA believes that NOX reduction

initiatives under title I and title IV

should be coordinated, consistent with

statutory requirements, in a way that

promotes the goal of achieving

necessary NOX reductions in a costeffective manner. In particular, today’s

proposed 40 CFR 76.16, which is

proposed to be added to 40 CFR part 76

of the Acid Rain regulations under title

IV, promotes this goal through

provisions that address the interaction

of: (i) efforts under title I, e.g., the

proposed transport rulemaking, to

reduce NOX emissions through cap-andtrade programs; and (ii) the

establishment of the title IV Phase II

NOX limits, i.e., the revised limits of

0.40 and 0.46 lb/mmBtu respectively for

tangentially fired and dry bottom, wallfired utility boilers and the new limits

of 0.68, 0.86, 0.84, and 0.80 lb/mmBtu

respectively for cell burner, cyclone,

wet bottom, and vertically fired utility

boilers.

Many utility boilers subject to the title

IV Phase II NOX limits are likely to face

significant, additional NOX reduction

requirements as a result of the proposed

SIP call. If, as EPA recommends, the

proposed SIP call requirements are

implemented in the form of a cap-andtrade program and the program results

in utility NOX emission reductions

exceeding those that would be required

by utility boilers complying with title IV

Phase II NOX limits, EPA believes that

the cap-and-trade system should be

relied on, in lieu of the title IV Phase II

NOX limits, to the fullest extent

permissible under the CAA. Under such

an approach, the reductions achievable

under title IV will still be realized but

in a manner that allows utilities to take

advantage of the cost savings that result

from flexibility, within a cap, to trade

allowances among utilities, as well as

among boilers owned by a single utility.

Under the Acid Rain Program in title IV

(as under other emission limit

programs), each individual utility boiler

must generally meet the applicable NOX

limit; only boilers with the same owner

or operator may average their emissions

and comply with a weighted average

NOX limit under a NOX averaging

plan.20 Relief from the title IV Phase II

NOX limits is appropriately limited to

utility boilers in the State or States

covered by the cap-and-trade regime.

Under today’s proposed § 76.16, the

Administrator retains the authority to

relieve boilers subject to a cap-and-trade

program under title I from the Phase II

NOX limits under section 407(b)(2) if the

Administrator finds that alternative

compliance through the cap-and-trade

program will achieve the same or more

overall NOX reductions from those

boilers than will the section 407(b)(2)

emission limitations. Section 76.16 sets

forth the criteria that the cap-and-trade

program must meet in order to ensure

that the program will yield the

necessary NOX reductions. Since

alternative compliance will be allowed

only if the necessary NOX reductions

will still be made, this approach is

consistent with the purposes of title IV

and the Act in general.

The EPA believes that it has the

authority under section 407(b)(2) to

provide relief from the revised Group 1

limits and the Group 2 limits where the

cap-and-trade program, replacing those

limits, provides for the same or greater

NOX emissions reductions and thus the

same or greater environmental

protection. With regard to Group 1

boilers not subject to the existing Group

1 limits until 2000 (i.e., Group 1 Phase

II boilers), section 407(b)(2) provides

that the Administrator ‘‘may’’ establish

more stringent emission limitations if

more effective low NOX burner

technology is available (42 U.S.C.

7651f(b)(2)). The Administrator

exercised her discretion to revise

generally the Group 1 limits because

more effective low NOX burner

technology is available, and the

resulting additional reductions are cost

effective, represent a reasonable step

toward achieving regional NOX

reductions that are likely to be needed,

and are consistent with section 401(b)

(61 FR 671137). If it is determined that,

for boilers in certain States, NOX

emissions will be the same or lower

under a cap-and-trade program than

under the revised Group 1 limits (and

the Group 2 limits), it is reasonable to

conclude that it is not necessary to

revise the Group 1 limits for those

boilers. Imposing the revised Group 1

limits on boilers subject to such a capand-trade program could limit the

flexibility of utilities under the cap-andtrade program and thereby limit the

potential cost savings from trading.

While emissions averaging under

section 407(e) provides some flexibility

for a utility to overcontrol at its cheaperto-control boilers and undercontrol at its

more-expensive-to-control boilers,

averaging is limited by statute to boilers

with the same owner or operator. In

contrast, under a cap-and-trade

program, utilities may overcontrol at

some of their units and sell NOX

allowances to other utilities that may

undercontrol at some of their units. It is

this greater flexibility, within a total

annual emissions cap, that provides the

opportunity to reduce compliance costs.

If boilers subject to a cap-and-trade

program are relieved of compliance with

the revised Group 1 limits, this will

likely result in achievement of

reductions in a more cost-effective

manner than if the revised Group 1

limits continued to be imposed on these

boilers.

Section 407(b)(2) gives the

Administrator discretion to make more

stringent the initial Group 1 limits

established in 1995, i.e., 0.45 and 0.50

lb/mmBtu respectively for tangentially

fired and dry bottom wall-fired utility

boilers (60 FR 18751), but not to relax

these initial limits. Thus, the initial

Group 1 limits will apply to Group 1

boilers covered by a cap-and-trade

program. While retaining the initial

Group 1 limits means that there may be

less flexibility than if there were no
25952 Federal Register / Vol. 63, No. 90 / Monday, May 11, 1998 / Proposed Rules

section 407 limits on these boilers,

relieving the boilers of the revised

Group 1 limits still results in some

increased flexibility and therefore is

likely to yield cost savings.

Similarly, with regard to Group 2

boilers, section 407(b)(2) requires that

the Administrator, taking account of

environmental and energy impacts, set

emission limits that are based on the

reductions achievable using available

control technologies with cost

effectiveness comparable to low NOX

burners on Group 1 boilers. In setting

the Group 2 limits, the Administrator

relied in part on the additional NOX

reductions that will result and

determined that these reductions are

cost effective, represent a reasonable

step toward achieving necessary

regional NOX reductions, and are

consistent with section 401(b) (61 FR

67114). Again, if greater reductions from

boilers in a State or group of States can

be achieved through a cap-and-trade

program in a more cost-effective manner

than through imposition of Group 2

limits (and revised Group 1 limits) on

the boilers, it is reasonable to relieve

those units of the Group 2 limits. Taking

account of these environmental and cost

impacts, the Administrator can, in such

circumstances, allow the cap-and-trade

program to apply in lieu of the Group

2 limits.

Proposed 40 CFR 76.16 establishes the

procedural and substantive

requirements for relieving boilers of the

revised Group 1 limits and the Group 2

limits. The proposed rule itself does not

grant or require such relief. Instead,

under the proposed rule, the

Administrator has the discretion to act,

on a case-by-case basis consistent with

the established procedures, to provide

such relief if he or she determines that

the substantive requirements are met.

Consideration of whether to relieve

boilers under a cap-and-trade program

of the section 407(b)(2) limits may be

initiated either by a petition by a State

or group of States or on the

Administrator’s own motion. Because of

the large number of utility companies

and coal-fired boilers and the

complexities that would result if relief

from the section 407(b)(2) limits were

considered on a boiler-by-boiler or

utility-by-utility basis, the rule requires

that any request for, and any

determination whether to grant, such

relief be made for an entire State or

entire group of States. The cap-andtrade program involved must cover, for

an entire State or group of States, all the

units for which relief is sought or

considered. This approach has the

added benefit of making it more likely

that the cap-and-trade program involved

will be broad enough to provide a robust

NOX allowance market.

Further, the cap-and-trade program

may be established through SIPs or FIPs

covering the States involved. The relief

from section 407(b)(2) limits is

potentially available whether the capand-trade program is adopted

voluntarily by States or imposed by EPA

under title I. State petitions for such

relief may be submitted, and the

Administrator’s consideration of

whether to grant relief may begin, before

the SIPs or FIPs (including revised SIPs

or FIPs) establishing the cap-and-trade

program are final and federally

enforceable. This allows the process of

deciding whether to grant relief from the

section 407(b)(2) limits to be

coordinated with the processing of these

SIPs or FIPs. However, relief may not be

granted until the SIPs or FIPs

establishing the cap-and-trade program

are actually in place, i.e., are final and

federally enforceable.

The substantive requirements that

must be met by the cap-and-trade

program are essentially the same

whether the program is implemented

through a SIP or FIP and whether the

consideration of relief from section

407(b)(2) limits is initiated by petition

or on the Administrator’s own motion.

The Administrator has discretion to

grant relief only if the cap-and-trade

program meets certain requirements

aimed at ensuring that the necessary

NOX reductions will still be achieved

and that the program creates an

opportunity for cost savings. First, each

unit that is in the State or group of

States and that would otherwise be

subject to title IV NOX emission limits

must be subject to either (i) a cap on

total annual NOX emissions or (ii) two

or more seasonal caps that together limit

total annual NOX emissions. This allows

for a cap-and-trade program with

different caps during different seasons,

e.g., a summer cap consistent with the

proposed trading rule and a cap for the

rest of the year.

Second, the units must be allowed to

trade authorizations to emit NOX within

the applicable cap. This element is what

provides utilities the flexibility to

reduce the costs of making the

reductions necessary for achievement of

the cap. If a utility demonstrates that

relief from the title IV Phase II NOX

limits for units in a given State will

make compliance less cost effective by

limiting the utility’s ability to use NOX

averaging plans to comply with the title

IV NOX limits that will still be

applicable to the utility’s units, the

Administrator is required to take this

into consideration in determining

whether to approve such relief for units

in that State.

Third, the units must surrender

authorizations to emit NOX (i.e., NOX

allowances) to account for their NOX

emissions during the period covered by

the cap. It should be noted that this

provision—and indeed the proposed 40

CFR 76.16 in general—do not address,

and do not either require or bar, banking

of NOX allowances.

In addition, the units must be

required to surrender allowances to

account for any NOX emissions

consequences of reducing utilization at

the generation facilities covered by the

cap and shifting utilization to

generation facilities not covered by the

cap. This addresses a problem that

potentially arises if a cap-and-trade

program covers some but not all

generation facilities. If, for example, a

utility can reduce the use of a unit

covered by the cap and offset the

resulting reduced generation with

increased generation at a unit not

covered by the cap, circumvention of

the cap may result. Shifting of

utilization may be accomplished

because of the nature of the electricity

industry, which in general operates

through an interstate transmission grid

to which the generation facilities are

connected. Because of the offsetting

utilization changes at the two units, the

atmosphere may receive the same total

amount of NOX emissions from the

units. In addition, since only the

reduced-utilization unit is subject to the

cap and so allowances are used only to

account for that unit’s emissions, the

unused allowances are available for use

by other units subject to the cap. The

net result is that the total emissions in

the atmosphere (including emissions by

the reduced-utilization unit, the

increased-utilization unit, and the units

acquiring and using the unused

allowances) may exceed the cap. This is

analogous to the reduced utilization

problem in the SO2 cap-and-trade

program in Phase I, during which most

units in the U.S. are not covered by the

requirement to hold allowances for their

SO2 emissions (58 FR 60950, 60951,

January 11, 1993). Section 408(c)(1)(B)

of the CAA and 40 CFR 72.91 and 72.92

of the acid rain regulations require SO2

allowance surrender to account for the

emissions consequences of reduced

utilization (60 FR 18462–63, 1995).

The NOX cap-and-trade program must

include appropriate allowance

surrender provisions to address this

problem by requiring NOX allowance

surrender to the extent necessary to

account for the increased NOX

emissions, if any, at generation facilities

(i.e., combustion devices serving
Federal Register / Vol. 63, No. 90 / Monday, May 11, 1998 / Proposed Rules 25953

generators) not covered by the cap. The

EPA recognizes that any allowance

surrender provisions can only

approximate the emissions

consequences of shifting utilization

from within-the-cap facilities to outsidethe-cap facilities, (60 FR 18466). The

EPA will evaluate NOX allowance

surrender provisions in light of this

limitation and of the importance of

adopting provisions that are workable

and not overly complicated. The EPA

believes that effective NOX allowance

surrender provisions can be developed

that are less complex than those in place

for reduced utilization in the SO2

allowance trading program. The EPA

also notes that the larger the group of

States covered by the cap, and the more

comprehensive the coverage by the cap

of generation facilities in such States,

the smaller the potential for shifting

utilization from units under the cap to

units outside the cap. The proposed

rule, therefore, provides that the

Administrator will consider showings

that accounting for shifting utilization is

not necessary because such shifting will

not likely result in higher total NOX

emissions from sources in the State or

the group of States involved or other

States.

Fourth, the total annual emissions by

all units that are subject to the cap and

that would otherwise be subject to the

section 407(b) limits must be equal to or

less than the total annual emissions of

such units if they were subject to the

section 407(b) limits (without adjusting

for alternative emission limitations and

NOX averaging plans). In determining

the units’ total annual emissions under

the section 407(b) limits, the effect of

alternative emission limitations—which

reduce the amount of NOX reductions

achieved and whose precise levels for

individual units would be difficult if

not impossible to project—will not be

considered. Requiring the cap-and-trade

program to yield the same or fewer total

annual emissions than the section

407(b) limits without considering

alternative emission limitations will

help ensure that the environmental

benefits of the section 407(b)(2) are

preserved under the cap-and-trade

program (Economic Incentive Program

Rules, 59 FR 16690, 16694, April 7,

1994).

In addition, the effect of averaging

will not be considered in determining

the units’ total annual NOX emissions

because of the following reasons. If

averaging is limited to units that are also

subject to the cap-and-trade program,

averaging is unnecessary to consider

separately because it would not affect

the total emissions of the averaging

units under the section 407(b) limits (60

FR 18756 which explains that,

considering actual annual utilization,

actual weighted average emission rate of

units in averaging plan cannot exceed

weighted average emission rate if each

unit had emitted at its 40 CFR 76.5,

76.6, or 76.7 limit and 60 FR 18769). If

averaging includes units not subject to

the cap-and-trade program and those

units select emission rates under the

plan that exceed the standard limits,

this could have the effect of

understating the reductions achieved

under the title IV limits.

In order to avoid disputes over what

period to use in comparing total annual

emissions under the cap-and-trade

program and the section 407(b) limits,

the rule specifies how to select the

period. The approach in the rule

ensures that actual data is available for

such period.

In addition to the substantive

requirements for relieving units of the

section 407(b)(2) limits, the rule

addresses the procedures that the

Administrator must follow in

determining whether to exercise his or

her discretion to grant relief. The

Administrator must make this

determination in a draft decision,

subject to notice and comment, and then

in a final decision. The draft decision

must set forth not only the

determination and its basis but also the

specific procedures that will govern the

issuance and any appeal of the final

decision.

The proposed 40 CFR 76.16 imposes

certain minimum procedural provisions

that must be set forth in the draft

decision. These procedural

requirements are closely modeled after

the procedures in 40 CFR part 72 of the

Acid Rain regulations for the issuance of

Acid Rain permits. Notice of the draft

decision must be provided by service on

interested persons, designated

representatives of any sources with

units otherwise subject to the title IV

Phase II NOX limits, and the air

pollution control agencies in States that

may be affected by the draft decision.

The State agencies that must be

provided notice include not only the

States in which the units involved are

located, but also neighboring States. The

description in the proposed rule of the

neighboring States (and areas in which

there are federally recognized Indian

Tribes) on which notice must be served

is based on the provisions of the

definition of ‘‘affected States’’ and the

affected State review provisions in the

40 CFR part 71 regulations, which

govern federal issuance of title V

operating permits (61 FR 34202, 34229,

and 34242–43, July 1, 1996). Notice

must also be provided in the Federal

Register and equivalent State

publications. Notice in newspapers in

general circulation in the areas in which

the units involved are located is not

required. The EPA maintains that

newspaper notice in these

circumstances is unnecessary,

particularly since any NOX cap-andtrade program being evaluated will have

to go through notice and comment in

order to be included in a SIP or FIP.

Newspaper notice could also be

unworkable in light of the number of

units and States that could be involved.

The provisions for public comment

period and public hearing are

essentially the same as those in 40 CFR

part 72. Notice must be given of the

final decision in the same manner as

notice of the draft decision. Any appeals

of the final decision are governed by 40

CFR part 78, which governs other acidrain-related decisions of the

Administrator.

Finally, after the Administrator

decides to relieve units of the section

407(b)(2) limits in light of a given capand-trade program, the SIP or FIP could

potentially be revised in a way that may

affect the cap-and-trade program and the

basis for the Administrator’s decision.

In such circumstances, the

Administrator may reconsider the

decision to grant relief from the section

407(b)(2) limits. The ability to

reconsider is explicitly preserved in the

rule in order to ensure that the

environmental benefit of the section

407(b)(2) limits that would otherwise

apply to the units involved continues to

be realized.

VII. Air Quality Assessment of the

Statewide Emissions Budgets

A. Background Information

This Section contains an assessment

of the impacts of the proposed budgets

on ozone concentrations within the

OTAG region. The assessment is based

on photochemical modeling of the

entire OTAG region for three emissions

scenarios, a Base Year, a 2007 Base Case

and the proposed statewide budgets.

Modeling was performed for the four

OTAG episodes using the OTAG version

of UAM-V. The emissions associated

with each State’s budget were modeled

collectively to examine the net benefits

of the budgets applied across the 23

jurisdictions. The procedures for

developing the emissions inputs for the

Base Case and the Budget scenario are

described in Section VII.B, Emissions

Scenarios. A number of metrics were

used to evaluate the impacts of the

budgets on ozone concentrations, as

described in Section VII, C, Analysis of

Modeling Results. Finally, the results of
25954 Federal Register / Vol. 63, No. 90 / Monday, May 11, 1998 / Proposed Rules

21Metrics are an aggregate of ozone

concentrations or the difference in ozone

concentrations between two or more scenarios.

Metrics are used to provide a means of

quantitatively evaluating multiple strategies.

22 In brief, this metric represents the sum of the

concentrations for all hourly ozone values >=125

ppb, divided by the area (km2) covered by

predictions >=125 ppb.

this assessment are provided in Section

VII.D, Analysis Results and Findings.

All of the model-ready emissions inputs

and model predictions can be obtained

in electronic form from the following

EPA website: http://www.epa.gov/

scram001/regmodcenter/t28.htm

B. Emissions Scenarios

The EPA modeled three emissions

scenarios for each of the four OTAG

episodes: Base Year, 2007 CAA Base

Case, and 2007 Budget (command and

control). Collectively, these scenarios

are designed to provide a means to

examine the expected impacts of the

proposed budgets on ozone within the

OTAG modeling domain. The Base Year

scenario is intended to generally reflect

emissions during the 1994–1996 time

period. The CAA Base Case reflects

growth to 2007 and controls mandated

by the 1990 Clean Air Act Amendments,

similar to the OTAG ‘‘2007 Base1c’’

scenario. The 2007 Budget scenario caps

NOX emissions, by State, at the level in

the SIP call, as modified to correct

minor errors and omissions identified

by EPA subsequent to the November 7,

1997 SIP call.

1. Development of Emissions Inputs

a. Electric Generation Sources. For

electric generation units (EGU), the Base

Year is a composite of 1995 and 1996.

The 1996 emissions were used unless

heat input at a State level was higher in

1995. For those States, 1995 emissions

were used. This is consistent with the

budget development approach. For the

2007 Base Case, growth was applied to

existing sources and CAA mandated

controls, including title IV and RACT,

were applied to all sources in the

modeling domain. No additional

controls beyond those mandated by the

CAA were applied. For the 2007 Budget

scenario, growth was applied to existing

sources and the emission rate for each

source >25 MWe in the 23 jurisdictions

covered by the SIP call was set at .15 lb/

mmBtu. Note that this application of the

.15 lb/MMBtu limit does not reflect an

emissions trading program. For sources

outside the 23 jurisdictions but inside

the modeling domain, the 2007 CAA

Base Case emission rates were retained.

Details on the development of these

emissions scenarios are described in the

revised Budget TSD.

b. Non-Electric Generation Point

Sources. For the non-EGU point sources,

the Base Year is 1995. The emissions are

essentially the OTAG 1990 emissions

projected to 1995 with a few minor

changes. The 2007 emissions are the

OTAG Base1c emissions with changes.

The main change that was made was to

reclassify certain sources as non-utility

where they were incorrectly classified

as utilities in the OTAG inventory. For

the Budget scenario, a 70 percent

reduction was applied to uncontrolled

2007 projected emissions for large

sources (i.e. >250 MMBtu/hr). For

medium sources (i.e. <=250 MMBtu/hr

and emitting more than 1 ton/day)

RACT was applied. For all small sources

in the 23 jurisdictions and all sources

outside these areas but inside the

modeling domain, the 2007 CAA Base

Case emissions were used.

c. Mobile and Area Sources. For the

highway, nonroad and stationary area

source sectors, EPA used the OTAG

1995 emissions for the Base Year and

the OTAG 2007 Basic emissions for the

2007 CAA Base Case. For the Budget

scenario, emissions for these sectors

were modeled using OTAG ‘‘level 0’’ for

highway mobile and OTAG ‘‘level 1’’ for

stationary and nonroad area sources

within the 23 jurisdictions covered by

the SIP call. For areas outside these

areas but inside the modeling domain,

the 2007 CAA Base Case emissions were

used.

2. Emission Summaries

State-level summaries of the weekday

NOX emissions used for modeling the

Base Year, 2007 CAA Base Case, and

Budget scenario are shown in Tables

VII–1 through VII–3, respectively. For

the purpose of these summaries, area

sources include both stationary and

nonroad area sources. The mobile

emissions are day-specific and are

presented for July 7, 1988. Where partial

States are included in the modeling

domain, only the emissions from the

part of the State in the domain are

presented. Table VII–4 shows the

percent reduction between the 2007

CAA Base Case and the Budget NOX

emissions used as input for modeling.

C. Analysis of Modeling Results

1. Technical Procedures

The impacts of the proposed budgets

on 1-hour and 8-hour ozone

concentrations in each State are

evaluated using various ozone

‘‘metrics’’ 21. The focus of the analysis is

on ozone predictions above the 1-hour

and 8-hour NAAQS in areas which

currently measure violations of these

standards. This State-level assessment is

supplemented with the OTAG Standard

Table of Metrics to quantify the impacts

in several ozone ‘‘problem areas’’

identified by OTAG. The remainder of

this Section describes the procedures for

calculating the metrics used in this

assessment.

a. State-Level Analysis. Nine metrics

were used to quantify the impacts of the

budgets on ozone concentrations in each

State. The metrics are listed below and

defined in Section C.1.a.ii, Procedures

for Calculating State-Level Metrics.

1-Hour Metrics

Metric 1—the number of grid cells

with 1-hour daily maximum ozone

concentrations >=125 ppb,

Metric 2—the magnitude and

frequency of the ‘‘ppb’’ reductions in 1-

hour daily maximum ozone

concentrations >=125 ppb,

Metric 3—the number of days with 1-

hour daily maximum ozone

concentrations >=125 ppb, and

Metric 4—the ‘‘areal exposure’’ to

hourly ozone concentrations >=125

ppb 22 (see definition in Section C.1.a.ii,

Procedures for Calculating State-Level

Metrics).

8-Hour Metrics

Metric 5—the number of grid cells

with average second high 8-hour ozone

concentrations >=85 ppb,

Metric 6—the magnitude and

frequency of the ‘‘ppb’’ reductions in

average second high 8-hour ozone

concentration >=85 ppb,

Metric 7—the number of grid cells

with 8-hour daily maximum ozone

concentrations >=85 ppb,

Metric 8—the magnitude and

frequency of the ‘‘ppb’’ reductions in 8-

hour daily maximum 8-hour ozone

concentrations >=85 ppb, and

Metric 9—the number of days with 8-

hour daily maximum ozone

concentrations >=85 ppb.

i. Selection of Grid Cells for Analysis.

As noted above, the focus of this

analysis is to evaluate the impacts of the

budgets on concentrations in areas

which violate the NAAQS. In this

regard, the first step in calculating the

metrics was to select appropriate sets of

grid cells for analysis. The approach to

grid cell selection is similar to that used

in the proposed SIP call, Section II,

‘‘Weight of Evidence Determination of

Significant Contribution’’ to quantify

the contributions from upwind

subregions on downwind

nonattainment. Different sets of grid

cells were selected for analyzing the

results relative the 1-hour NAAQS and

the 8-hour NAAQS. For both standards,

there are two generic types of grid cells.

The first type must meet the following
Federal Register / Vol. 63, No. 90 / Monday, May 11, 1998 / Proposed Rules 25955

23Note that EPA followed the procedures

established by OTAG by excluding predictions from

the first three days of each episode from the

calculation of metrics. These days are considered

‘‘ramp-up’’ days when ‘‘initial’’ conditions to the

model might effect predictions.

two-part test: (a) The grid cell must

correspond geographically to (i.e.

overlay) a county which currently

violates the NAAQS and (b) the grid cell

must have predicted ozone

concentrations above the concentration

level of the NAAQS (e.g. >=125 ppb for

the 1-hour NAAQS and >=85 ppb for the

8-hour NAAQS). The second generic

type of grid cell must meet only the

second part of this two part test. That is,

the grid cell must have predicted ozone

above the NAAQS but may or may not

be associated with a county violating

the NAAQS. The 1-hour and 8-hour

State-level metrics identified above

were calculated for both types of grid

cells. The rationale and procedures

followed in the grid cell selection

process are described below.

First, 1994–1996 ambient monitoring

data were used to identify counties

which currently violate the 1-hour and

8-hour NAAQS. A list of these counties

is contained in the docket for this

notice. The grid cells in the OTAG

region were then screened to identify

those grids which at least partially

overlay one of the 1-hour violating

counties. The same procedure was

followed using the 8-hour violating

counties. This process resulted in one

set of grid cells associated with areas

violating the 1-hour NAAQS and a

separate set associated with areas

violating the 8-hour NAAQS. The next

step was to select the subset of 1-hour

‘‘violating grid cells’’ which also have

predicted ozone concentrations above

the NAAQS. For this, the 1-hour daily

maximum concentrations for the 2007

Base Case model runs were examined to

identify which grid cells had predicted

values >=125 ppb during any one of the

4 episodes. The grid cells that met this

test were then selected for analysis

using the 1-hour metrics.

For the 8-hour analysis, the

procedures for selecting the subset of

grid cells was more complicated due to

the distinction between the form of the

8-hour NAAQS and the episodic nature

of the model predictions. In this regard,

two sets of 8-hour predictions were

included for analysis. One set considers

those grid cells with 8-hour daily

maximum concentrations >=85 ppb in

the 2007 Base Case model runs (this set

is analogous to the set of 1-hour data

described above). Thus, a set of grid

cells which (a) corresponds to counties

violating the 8-hour NAAQS and (b) has

8-hour predictions >=85 ppb was

selected for calculating the 8-hour

metrics. However, although the analysis

of 8-hour daily maximum values may

provide useful information on the

impacts of the budgets relative to high

8-hour concentrations, these data do not

necessarily correspond to the form of

the 8-hour NAAQS. In this regard, we

also considered the approach followed

in the proposed SIP call for dealing with

this issue. That approach involved using

ozone measurements to ‘‘link’’ the

fourth highest 8-hour form of the

NAAQS, based on three years of data, to

the episodes modeled by OTAG (Staff

Report-Procedures for Linking the

OTAG Episodes to the 8-Hour Ozone

NAAQS, October 1997, docket number,

II–A–25). The results of that analysis

indicate that the episodic average of the

second highest 8-hour observed

concentrations during the 1991, 1993,

and 1995 episodes correspond best

‘‘overall’’ to the fourth highest 8-hour

values calculated using 3 years of

measured data. For the assessment of

the budgets, the second highest 8-hour

values averaged across the 1991, 1993,

and 1995 episodes were calculated for

each grid cell. Those grid cells which (a)

correspond to counties violating the 8-

hour NAAQS and (b) have an average

second high 8-hour prediction >=85 ppb

were selected for calculating the 8-hour

metrics. Thus, for the 8-hour analysis,

separate metrics were calculated for the

daily maximum 8-hour values and for

the average second high 8-hour values.

The previous discussion dealt with

selecting grid cells which meet the twopart ‘‘monitoring plus modeling’’ test for

both the 1-hour and 8-hour NAAQS.

The other type of grid cell selected for

analysis must only meet the model

prediction part of the tests described

above. The rationale for using this

second type of grid cell is discussed

next. Although the ‘‘violating county’’

grid cells may be most appropriate for

this assessment because they are

associated with areas violating the

NAAQS, there are a number of

limitations with this approach which

warrant further consideration. First, in

terms of the modeling data, the

requirement that high ozone predictions

spatially coincide with violating

counties may be overly limiting given

the uncertainties in the modeled wind

regimes associated with the regional

nature of the meteorological inputs.

Also, the set of ‘‘violating county’’ grid

cells excludes all grid cells that are over

water and not touching any State land

areas. In the real atmosphere, sea breeze

and lake breeze wind flows can

transport high ozone levels over water

back on-shore to affect coastal land

areas. This meteorological process is not

fully treated in the model because of the

coarse horizontal resolution of the grid

cells (i.e. 12 km). Thus, high

concentrations predicted just offshore

may be inappropriately excluded from

an analysis that is limited to the set of

‘‘violating county’’ grid cells. In terms of

limitations to the monitoring data, there

are relatively large areas in some

portions of the domain without any

monitors. Since the model predicts

concentrations in grid cells which cover

the entire domain, the model

predictions may indicate an ozone

problem in areas without monitors. In

an attempt to address these concerns,

grid cells were selected for analysis

based on model predictions only. The

criteria for selecting these grid cells

involved the modeling part of the two

part test described above. That is, for the

1-hour NAAQS a set of grid cells was

selected if they have daily maximum 1-

hour predictions >=125 ppb. Similarly,

there are two sets of 8-hour grid cells.

One set contains those grid cells with

daily maximum 8-hour predictions

>=85 ppb and the other set contains grid

cells with an average second high 8-

hour value >=85 ppb. Also, note that in

this approach, all grid cells over land as

well as over each of the Great Lakes and

in a band 60 km (5 grid cells) wide

along the East Coast are considered

depending on whether or not they

passed these 1-hour and 8-hour

concentration tests.

ii. Procedures for Calculating StateLevel Metrics. Each of the 1-hour and 8-

hour metrics identified in Section C.1.a,

State-Level Analysis, was calculated for

the two types of grid cells described

above. The procedures for calculating

these metrics are described next. The

results are discussed in Section D,

Analysis Results and Findings. Metric 1

was calculated by first screening the

2007 Base Case 1-hour daily maximum

predictions for each grid cell to select

only those days with concentrations

>=125 ppb. The daily maximum

predictions from the Budget scenario for

these same days and grids were also

selected for analysis. The values from

the Budget scenario were then

subtracted from the corresponding 2007

Base Case values to derive a set of

‘‘ppb’’ differences for each day 23 and

grid cell with ozone >=125 ppb in the

Base Case. These ‘‘ppb’’ reductions were

then grouped into seven concentration

ranges (i.e. 2–5 ppb, 5–10 ppb, 10–15

ppb, 15–20 ppb, 20–25 ppb, and >25

ppb) and tallied by State. Metric 2 is

simply a tabulation of the number of

grid cells with at least one daily

maximum ozone 1-hour concentration

>=125 ppb. This metric was calculated
25956 Federal Register / Vol. 63, No. 90 / Monday, May 11, 1998 / Proposed Rules

for both the 2007 Base Case and the

Budget scenario. For Metric 3, the

number of days with a daily maximum

ozone prediction >=125 ppb was tallied

for each grid cell for both the 2007 Base

Case and for the Budget scenario. These

data were aggregated to show the

number of grid cells that had 1 day, 2–

4 days, 5–9 days, 10–14 days, or >=15

days with predicted 1-hour daily

maximum ozone concentrations >=125

ppb. Metric 4 (areal exposure) was

calculated by first summing all hourly

concentrations that are >=125 ppb (i.e.

add together the predicted hourly ‘‘ppb’’

values that are >=125 ppb) for each grid

cell individually, for each day. These

‘‘daily exposure’’ values in each grid

were then summed by grid cell over all

days in all 4 episodes to produce the

total exposure for each grid cell. The

resulting grid cell exposure values were

summed by State for all grid cells (with

predictions >=125 ppb) in the State. The

State total exposure values were then

divided by the total area covered by the

grid cells used in the calculations to

produce the ‘‘areal exposure’’ values in

units of ppb-hrs per km 2.

Procedures for calculating the five 8-

hour metrics are similar to those

followed for calculating the

corresponding 1-hour metrics except

that the 8-hour values (i.e. the 8-hour

daily maxima and the average second

high 8-hour values) were used in the

calculations.

b. OTAG Standard Table of Metrics.

As part of OTAG, a Standard Table of

Metrics was developed to evaluate the

relative effectiveness of OTAG’s

strategies. This table contains a set of 22

metrics which are calculated for each of

22 geographic areas. The OTAG

Standard Table of Metrics for the Budget

scenario compared to the 2007 Base

Case is provided in the docket. From

this full set of data, five of the metrics

calculated for the 12 OTAG ozone

‘‘problem areas’’ were selected for

analysis because of their relevance to

this assessment. These metrics are listed

below. The remaining OTAG metrics

were not considered as applicable

primarily because they do not focus on

concentrations above the NAAQS. The

12 OTAG ‘‘ozone problem areas’’ are

shown in Figure 1. The other 10 areas

for which the OTAG metrics were

calculated overlap these 12 areas. Note

that the OTAG metrics are calculated

using all grid cells that meet the criteria

of the individual metrics. No attempt

was made by OTAG to relate the grid

cells used in these calculations to

counties violating the NAAQS.

1-hr Metrics

• Number of grid cells with a 1-hour

daily maximum ozone concentrations

>124 and >140 ppb,

• ‘‘Weighted sum of differences’’

when the 2007 Base Case prediction is

>124 ppb,

• Number of grid cells with a

decrease of more than 4 ppb (2007 Base

vs Budget) in daily maximum ozone

when the 2007 Base Case ozone is >124

ppb, and

• Number of grid cells with an

increase of more than 4 ppb (2007 Base

vs Budget) in daily maximum ozone

when the 2007 Base Case ozone is >124

ppb.

8-hr Metrics

• Number of grid cells with 8-hour

daily maximum ozone concentrations

>84 and >100 ppb.

The preceding 1-hour and 8-hour

OTAG metrics are self-explanatory,

except for the ‘‘weighted sum of

differences.’’ In calculating this metric

the change in daily maximum 1-hour

ozone in a grid cell is multiplied by the

corresponding 2007 Base Case ozone

prediction in that grid cell. These

concentration-‘‘weighted’’ differences

are calculated for each day and then

summed for the episode. Finally, the

sum of ‘‘weighted’’ differences is

divided by the sum of the 2007 Base

Case daily maximum concentrations to

produce the values for this metric. This

metric provides a means for examining

the ‘‘average’’ ozone reduction in a way

that gives more importance or ‘‘weight’’

to reductions that occur at high

concentrations.

D. Analysis Results and Findings

1. Introduction

The results and conclusions found in

this Section are based on the suite of

metrics outlined above in Section C,

Analysis of Modeling Results. The

discussion is organized such that the

impacts on 1-hour concentrations and

the impacts on 8-hour concentrations

are presented separately. For each

NAAQS the results for the State-level

metrics are followed by the results for

the OTAG ‘‘problem areas.’’

As indicated in Section C.1, Technical

Procedures, the focus of this assessment

is on the impacts of the budgets on 1-

hour and 8-hour ozone above the

NAAQS in areas which currently

measure violations of these standards.

In this regard, the discussion of the

State-level impacts addresses only those

metrics calculated using the ‘‘violating

county’’ grid cells. The data for all

metrics calculated using the set of grid

cells selected based on model

predictions only are included in the

docket. Also, the discussion for the 8-

hour NAAQS is based on the metrics

calculated for the average second high

8-hour concentrations since this was

found to best represent the form of the

8-hour NAAQS. The data for metrics

calculated using the 8-hour daily

maximum predictions are included in

the docket.

For the State-level analyses, the

modeling domain was divided into

several regions. The impacts across the

23 jurisdictions subject to the SIP call

are addressed separately for States in

the Midwest, Southeast, and Northeast.

The States included in each of these

regions are listed in Table VII–5. For

completeness, all of the metrics were

also calculated for those States within

the domain that are not subject to the

SIP call. These data are included in the

docket.

a. Impacts on 1-Hour Ozone

Concentrations. The State-level analyses

of 1-hour concentrations included

Metrics 1–4: (1) The number of grid

cells with 1-hour daily maximum

concentrations >= 125 ppb; (2) the

magnitude and frequency of the ‘‘ppb’’

reductions in 1-hour daily maximum

ozone concentrations >= 125 ppb; (3)

the number of days with 1-hour daily

maximum ozone concentrations >= 125

ppb; and, (4) the ‘‘areal exposure’’ to

hourly ozone concentrations >= 125

ppb. For ease of communication in the

discussion of results, the following

terminology is used in referring to these

metrics:

Metric 1: the extent of

‘‘nonattainment,’’

Metric 2: the magnitude and

frequency of ‘‘nonattainment,’’

Metric 3: the number of

‘‘nonattainment’’ days in each grid cell,

and

Metric 4: exposure to

‘‘nonattainment.’’

In addition to the State-level analysis,

the impacts on 1-hour ozone in the

OTAG ‘‘problem areas’’ were

investigated using several of the

standard OTAG metrics, including: (1)

The number of grid cells with daily

maximum 1-hour ozone >124 ppb; and

the number of grid cells with daily

maximum 1-hour ozone >140 ppb; (2)

the weighted sum of differences when

the 2007 Base Case prediction is >124

ppb; and, (3) the number of grid cells

with an increase of more than 4 ppb

when the 2007 Base Case ozone is >124

ppb versus the number of grid cells with

a decrease of more than 4 ppb when the

2007 Base Case ozone is >124 ppb. This

last metric is designed to compare the

regional benefits of NOX emissions

reductions to possible local disbenefits.
Federal Register / Vol. 63, No. 90 / Monday, May 11, 1998 / Proposed Rules 25957

The results for these OTAG metrics

follow the discussion of the State-level

results.

i. State-Level Analyses—1-Hour

Concentrations. The 1-hour metrics for

States in the Midwest, Southeast, and

Northeast are provided in Tables VII–6,

VII–7, and VII–8, respectively. For the

Midwest, the results indicate that the

overall extent of 1-hour nonattainment

(Metric 1) is reduced by 74 percent in

this region as a result the emissions

reductions provided by the Budget

scenario. The results for Metric 2

indicate that over 50 percent of the

‘‘ppb’’ reductions in ozone are in the

10–15 ppb range or greater, with

reductions in the magnitude of

nonattainment at more than 25 ppb in

Illinois and Indiana. In Michigan, nearly

all of the reductions were in the range

of 10–15 ppb or more. The results for

Metric 3 show a large reduction in the

number of 1-hour nonattainment days in

four out of the five States having

nonattainment in the 2007 Base Case.

Note that although the number of

nonattainment days in Ohio did not

decline, the concentrations on these

days were reduced, but not to below 125

ppb. In terms of exposure to

nonattainment (Metric 4), there were

large reductions in exposure for each of

the 3 episodes that produced high

concentrations in this region (i.e. 1988,

1991, and 1995). Overall, exposure to

nonattainment was reduced by 77

percent in the Midwest as a result of the

emissions reductions associated with

the budget.

States in the Southeast are also

predicted to have large benefits in

mitigating the 1-hour nonattainment

problem as a result of the budgets. The

overall extent of nonattainment (Metric

1) is predicted to decline by 44 percent

in this region with reductions of

approximately 50 percent in Tennessee

and Alabama. Large ‘‘ppb’’ reductions

are also predicted using Metric 2. The

four States with 1-hour nonattainment

problems in the region (Alabama,

Georgia, Tennessee, and Virginia) have

reductions of 15 ppb or more. In

Alabama, 34 percent of the reductions

exceed 20 ppb and in Georgia, 48

percent of the reductions exceed 20 ppb.

The number of nonattainment days is

also reduced in the Southeast (Metric 3),

but not to the same degree as in the

Midwest. Still, the number of grid cells

with one or more nonattainment days is

reduced by 25 percent in Georgia and by

38 percent and 43 percent in Alabama

and Tennessee, respectively. Looking at

Metric 4 indicates that the total

exposure to nonattainment across the

Southeast was cut in half. For

individual States and specific episodes,

the reduction in exposure in this region

ranged from 30 percent to 100 percent.

The emissions reductions in the

budget are predicted to produce an

overall 48 percent decline in the extent

of nonattainment in the Northeast

(Metric 1). The extent of nonattainment

in Maryland and Pennsylvania was

reduced by approximately 50 percent

and by more than 70 percent in

Delaware, Massachusetts, New Jersey,

and Rhode Island. The ‘‘ppb’’

reductions (Metric 2) were greater than

25 ppb in Delaware, Maryland,

Massachusetts, New Jersey, and

Pennsylvania. The results for Metric 2

also indicate that the magnitude of

nonattainment is reduced by 15 ppb or

more in seven of the Northeast States

(Connecticut, Delaware, Maryland,

Massachusetts, New Jersey, New York,

and Pennsylvania). The total number of

grid cells across the region with more

than two nonattainment days declined

by 46 percent (Metric 3), while the

number of grid cells with more than five

nonattainment days declined by 75

percent. Also, the exposure to

nonattainment (Metric 4) in the

Northeast was reduced in half as a result

of the budgets. Except for Washington,

DC, which had relatively low exposure

because it covers a much smaller area

than the Northeast States, the total

exposure to nonattainment was reduced

in the range from 44 percent in

Connecticut to 89 percent in Maine.

ii. Ozone Problem Area Analyses—1-

Hour Concentrations. In reviewing the

metrics for the ozone ‘‘problem areas,’’

the analyses are restricted to the 3

sections of the Northeast Corridor and

selected ozone problem areas:

Richmond, Atlanta, Nashville, St. Louis,

Louisville-Cincinnati, Lake Michigan

Area, Detroit, Pittsburgh and Charlotte.

The metrics are presented in Table VII–

9 for each episode considered along

with a composite for all four episodes.

The results for the three portions of

the Northeast Corridor indicate that

there is an overall decline of 40 percent

to 67 percent in the number of grid cells

with concentrations exceeding 124 and

a somewhat comparable decrease of 51

percent to 65 percent in exceedences of

140 ppb. Reductions in these two

metrics occur across all four episodes.

The ‘‘weighted sum of differences’’

metric provides a way to quantify the

‘‘ppb’’ reductions in ozone with greater

‘‘weight’’ given to the reductions when

concentrations are high. The results for

this metric indicate that most of the

‘‘ppb’’ reductions in the three Northeast

Corridor areas range from approximately

12 ppb to 18 ppb.

Examining the 1-hour metrics for the

other problem areas indicates that all of

the areas were predicted to have large

decreases in the number of grid cells

exceeding 124 ppb and 140 ppb. In

general, the reductions in this metric are

comparable to what was predicted for

the Northeast Corridor. Specifically, in

six areas (Nashville, LouisvilleCincinnati, Richmond, St Louis,

Pittsburgh, and Charlotte), the number

of grid cells >124 ppb decreases by 70

percent or more. Considering the

‘‘weighted sum of differences’’ metric,

the ‘‘ppb’’ reduction in six of the areas

outside the Northeast Corridor (Atlanta,

Richmond, Nashville, LouisvilleCincinnati, Pittsburgh, and Charlotte)

were generally close to, or greater than,

20 ppb.

In addition to evaluating the impact of

the budgets in terms of ozone

reductions, the model predictions were

also examined to determine the extent

of any increase or ‘‘disbenefit’’ in ozone

concentrations. In this regard, EPA

compared the number of grid cells

exceeding 124 ppb that had more than

a 4 ppb increase versus the number of

such grid cells with more than a 4 ppb

decrease. The results indicate that the

extent of reductions in ozone far

exceeds any increases. In two of the

three Northeast Corridor areas, as well

as in all of the other problem areas,

more than 90 percent of the daily

maximum values exceeding 124 ppb

were reduced by 4 ppb or more. In terms

of ozone ‘‘disbenefits,’’ five areas had no

increases greater than 4 ppb. In those

areas with a predicted increase, these

increases represent a very small fraction

of the total number of exceedences of

124 ppb.

b. Impacts on 8-Hour Ozone

Concentrations. The analyses presented

in this Section for the 8-hour ozone

concentrations follow the same format

as the previous discussion on 1-hour

ozone concentration metrics. The Statelevel analysis is presented first followed

by the analysis of the OTAG Metrics.

The State-level metrics include Metric

5: the number of grid cells with average

second high 8-hour ozone

concentrations >= 85 ppb and Metric 6:

the magnitude and frequency of the

‘‘ppb’’ reductions in average second

high 8-hour ozone concentrations >= 85

ppb. Note that fewer 8-hour metrics are

considered in this analysis because the

link to the form of the 8-hour NAAQS

results in a single average second high

value in each grid cell. Thus, metrics

involving ‘‘multiple days’’ or ‘‘multiple

hours’’ are not directly applicable to the

8-hour NAAQS. Like the 1-hour

discussion, for ease of communication

of results, the following terminology is

used in referring to these metrics:
25958 Federal Register / Vol. 63, No. 90 / Monday, May 11, 1998 / Proposed Rules

Metric 5: the extent of

‘‘nonattainment’’ and

Metric 6: the magnitude and

frequency of reductions in

‘‘nonattainment.’’

The 8-hour analysis includes the same

geographic regions as the 1-hour

analysis.

i. State-Level Analyses—8-Hour

Concentrations. The results for the 8-

hour metrics are presented for the

Midwest, Southeast and Northeast in

Tables VII–10, VII–11, and VII–12,

respectively. In the Midwest, the

proposed budgets reduced the overall

extent of 8-hour nonattainment (Metric

5) by 89 percent. Six States (Kentucky,

Indiana, Illinois, Michigan, Ohio, and

West Virginia) have reductions of more

than 80 percent. The magnitude and

frequency of reductions is also large

(Metric 6). Specifically, 97 percent of all

of the ‘‘ppb’’ reductions are 5 ppb or

greater and 21 percent of the reductions

are 15 ppb or greater. In the Southeast,

the overall extent of nonattainment

(Metric 5) declines by 78 percent. All of

the States in this region (Alabama,

Georgia, North Carolina, South Carolina,

Tennessee, and Virginia) show a decline

in this metric of 60 percent or more. In

addition, 80 percent of the ‘‘ppb’’

reductions are 10 ppb or greater with

reductions of over 20 ppb in North

Carolina. The Northeast region has a

somewhat lesser reduction in the extent

of 8-hour nonattainment (Metric 5)

compared to the other two regions, with

an overall reduction in this metric of 65

percent. Two States (New Jersey and

Connecticut) have reductions in the

extent of 8-hour nonattainment of

approximately 60 percent while two

other States (Delaware and

Pennsylvania), along with Washington,

DC have reductions in this metric of

over 90 percent. In terms of the

magnitude of the ‘‘ppb’’ reductions in

nonattainment (Metric 6),

approximately 97 percent of the

reductions are greater than 5 ppb, 62

percent are greater than 10 ppb, and 9

percent are greater than 15 ppb. Looking

at the individual States indicates that

four States (Delaware, Maryland, New

Jersey, and Pennsylvania) all have

‘‘ppb’’ reductions in the 15–20 ppb

range.

ii. Ozone Problem Area Analyses—8-

Hour Concentrations.

To investigate impacts on 8-hour

ozone in the OTAG ‘‘problem areas,’’

two of the standard OTAG metrics were

analyzed:

• the number of grid cells with 8-hour

daily maximum ozone > 84 ppb; and

• the number of cells with 8-hour

daily maximum ozone > 100 ppb.

The results, as provided in Table VII–

13, indicate that the extent of high 8-

hour concentrations in the northern and

central portions of Northeast Corridor is

generally reduced by 30 percent to 40

percent, considering all 4 episodes

combined. The reductions are somewhat

greater in the southern Corridor at 46

percent to 67 percent. For the problem

areas outside the Corridor, seven of the

areas (Atlanta, Charlotte, LouisvilleCincinnati, Nashville, Pittsburgh, and

Richmond) had reductions of

approximately 60 percent or more in the

extent of 8-hour concentrations

exceeding 84 ppb and 100 ppb.

2. Summary and Conclusions

In summary, the air quality impacts of

the proposed budgets were modeled for

the four OTAG episodes. The result

were evaluated by comparing ozone

predictions from the Budget scenario to

a 2007 Base Case reflecting emissions

reductions associated with CAA control

programs. A number of 1-hour and 8-

hour metrics were used to quantify the

impacts at the State-level. In addition,

several of the relevant metrics from the

OTAG Standard Table of Metrics were

examined to evaluate the impacts in

ozone ‘‘problem areas’’ within the

region.

The results of this analysis lead to the

following major conclusions:

(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, the analysis indicates that

nonattainment problems requiring

additional local control measures will

likely continue in some areas currently

violating the NAAQS (see also Section

I.B, Updates with 1994–96 Air Quality

Data).

E. Alternative Approaches

The effect of NOX emissions on air

quality in areas violating air quality

standards depends, in part, on the

distance between sources and receptor

areas. Sources that are closer to areas

violating air quality standards tend to

have larger effects on air quality than

sources that are far away. If there is

significant variation in the contribution

of emissions in different subregions

within the 23-jurisdiction area,

alternative approaches to calculating

States’ budgets other than those based

on the application of uniform control

measures will be evaluated. On the

other hand, the large number of

nonattainment areas spread out over the

region and the several different weather

patterns associated with summertime

ozone pollution episodes should also be

considered when evaluating a

subregional approach. The EPA plans to

evaluate alternative approaches in

developing the final rule. These will

consider alternative uniform approaches

at levels below and above the proposal

level as well as regional approaches that

apply different control levels to

different geographic regions.

The EPA solicited comment in the

November 7, 1997 NPR on approaches

for establishing State emissions budgets

that factor in the differential effects on

air quality in areas violating a standard.

Comments advocating alternative

approaches would be most helpful if

they set forth concrete proposals on

what analysis should form the basis of

budget calculations. For example, some

have suggested an approach that would

attempt to quantify more explicitly the

cost effectiveness of emissions

reductions in terms of improvements in

ambient ozone concentrations in areas

violating a standard (measured, for

example, as cost per populationweighted changes in parts per billion

peak ozone concentration) taking into

account the location of control measures

through subregional modeling. If after

review of alternative approaches

(including sub-regional modeling

analyses submitted by the States and

other commenters), EPA concludes that

a new approach is appropriate, EPA will

issue a SNPR.

BILLING CODE 6560–50–P
Federal Register / Vol. 63, No. 90 / Monday, May 11, 1998 / Proposed Rules 25959

Figure VII–1. Twelve of the Ozone ‘‘Problem Areas’’ Selected by OTAG

BILLING CODE 6560–50–C
25960 Federal Register / Vol. 63, No. 90 / Monday, May 11, 1998 / Proposed Rules

TABLE VII–1.—BASE YEAR (1995/96) MODELING EMISSIONS OF NOX

[Tons/day]

State EGU Non-EGU Area Highway Total

Alabama .................................................................................................... 720.16 246.58 351.01 431.09 1748.84

Arkansas ................................................................................................... 188.47 58.55 212.98 232.64 692.64

Connecticut ............................................................................................... 54.10 36.10 128.47 211.86 430.53

Delaware ................................................................................................... 58.64 28.26 45.35 63.44 195.69

District of Columbia .................................................................................. 3.97 2.58 18.52 19.96 45.03

Florida ....................................................................................................... 1004.44 121.73 375.44 793.65 2295.26

Georgia ..................................................................................................... 634.73 185.30 290.50 655.60 1766.13

Illinois ........................................................................................................ 862.93 519.40 552.99 724.46 2659.78

Indiana ...................................................................................................... 1138.63 280.04 380.34 495.91 2294.92

Iowa .......................................................................................................... 252.19 69.31 179.77 239.78 741.05

Kansas ...................................................................................................... 277.06 159.31 430.15 193.23 1059.75

Kentucky ................................................................................................... 1107.62 103.18 457.30 358.09 2026.19

Louisiana ................................................................................................... 346.66 870.30 720.25 300.05 2237.26

Maine ........................................................................................................ 9.43 52.03 32.32 118.05 211.83

Maryland ................................................................................................... 336.13 90.36 186.20 307.20 919.89

Massachusetts .......................................................................................... 111.40 73.86 235.31 290.73 711.30

Michigan .................................................................................................... 555.44 353.14 383.65 633.21 1925.44

Minnesota ................................................................................................. 215.18 61.45 182.61 360.58 819.82

Mississippi ................................................................................................. 194.65 173.26 278.40 270.34 916.65

Missouri ..................................................................................................... 588.13 74.08 237.45 417.50 1317.16

Nebraska ................................................................................................... 96.15 36.86 142.89 116.47 392.37

New Hampshire ........................................................................................ 65.36 6.97 43.95 96.20 212.48

New Jersey ............................................................................................... 143.02 143.33 265.11 404.10 955.56

New York .................................................................................................. 375.07 126.63 494.87 823.37 1819.94

North Carolina ........................................................................................... 969.62 186.09 238.08 608.02 2001.81

North Dakota ............................................................................................. 0.00 0.46 26.11 16.53 43.10

Ohio .......................................................................................................... 1701.82 307.42 478.37 757.73 3245.34

Oklahoma .................................................................................................. 337.30 100.69 400.76 316.23 1154.98

Pennsylvania ............................................................................................. 878.45 531.22 402.97 630.38 2443.02

Rhode Island ............................................................................................. 21.82 2.21 28.05 53.40 105.48

South Carolina .......................................................................................... 429.77 169.16 164.21 352.85 1115.99

South Dakota ............................................................................................ 44.54 0.37 23.65 51.03 119.59

Tennessee ................................................................................................ 957.50 371.13 452.50 474.18 2255.31

Texas ........................................................................................................ 1172.84 1290.89 760.77 1200.77 4425.27

Vermont .................................................................................................... 0.20 1.04 13.32 60.65 75.21

Virginia ...................................................................................................... 432.34 146.16 357.88 578.05 1514.43

West Virginia ............................................................................................. 873.65 282.88 137.26 168.66 1462.45

Wisconsin .................................................................................................. 311.71 110.90 224.92 360.40 1007.93

Total ................................................................................................... 17471.12 7373.23 10334.68 14186.39 49365.42

TABLE VII–2.—2007 CAA BASE CASE MODELING EMISSIONS OF NOX

[Tons/day]

State EGU Non-EGU Area Highway Total

Alabama .................................................................................................... 619.16 314.95 361.70 416.80 1712.61

Arkansas ................................................................................................... 241.34 67.74 278.52 218.21 805.81

Connecticut ............................................................................................... 62.85 37.62 120.02 159.47 379.96

Delaware ................................................................................................... 85.86 34.82 40.33 60.30 221.31

District of Columbia .................................................................................. 3.81 2.03 26.99 20.96 53.79

Florida ....................................................................................................... 1193.66 143.06 396.06 935.38 2668.16

Georgia ..................................................................................................... 635.45 224.98 306.47 599.03 1765.93

Illinois ........................................................................................................ 908.72 442.08 558.24 622.86 2531.9

Indiana ...................................................................................................... 1164.89 344.53 426.76 491.79 2427.97

Iowa .......................................................................................................... 318.51 79.17 193.78 242.36 833.82

Kansas ...................................................................................................... 278.16 200.10 387.65 206.14 1072.05

Kentucky ................................................................................................... 958.00 125.90 486.02 338.91 1908.83

Louisiana ................................................................................................... 370.72 797.24 764.56 288.99 2221.51

Maine ........................................................................................................ 7.31 62.32 39.78 116.31 225.72

Maryland ................................................................................................... 289.05 94.67 227.65 271.66 883.03

Massachusetts .......................................................................................... 188.69 72.86 239.72 240.22 741.49

Michigan .................................................................................................... 511.62 402.98 428.71 622.31 1965.62

Minnesota ................................................................................................. 269.07 74.35 188.95 375.95 908.32

Mississippi ................................................................................................. 239.02 180.66 406.62 246.82 1073.12

Missouri ..................................................................................................... 604.78 81.31 224.18 420.19 1330.46

Nebraska ................................................................................................... 93.92 41.46 136.45 119.41 391.24

New Hampshire ........................................................................................ 118.61 8.03 36.31 86.94 249.89

New Jersey ............................................................................................... 154.00 145.28 271.11 381.86 952.25
Federal Register / Vol. 63, No. 90 / Monday, May 11, 1998 / Proposed Rules 25961

TABLE VII–2.—2007 CAA BASE CASE MODELING EMISSIONS OF NOX—Continued

[Tons/day]

State EGU Non-EGU Area Highway Total

New York .................................................................................................. 356.59 138.02 391.91 777.35 1663.87

North Carolina ........................................................................................... 672.59 227.44 250.26 551.56 1701.85

North Dakota ............................................................................................. 0.00 0.40 37.24 17.47 55.11

Ohio .......................................................................................................... 1237.97 361.08 494.11 710.83 2803.99

Oklahoma .................................................................................................. 365.45 124.90 521.39 316.14 1327.88

Pennsylvania ............................................................................................. 906.73 558.46 382.86 556.86 2404.91

Rhode Island ............................................................................................. 10.47 2.34 22.85 51.46 87.12

South Carolina .......................................................................................... 437.29 235.36 186.94 365.30 1224.89

South Dakota ............................................................................................ 49.91 0.64 34.31 51.89 136.75

Tennessee ................................................................................................ 610.64 461.38 517.64 496.75 2086.41

Texas ........................................................................................................ 1271.05 1114.13 825.12 1073.35 4283.65

Vermont .................................................................................................... 0.20 1.04 13.76 63.05 78.05

Virginia ...................................................................................................... 415.27 168.41 411.85 603.89 1599.42

West Virginia ............................................................................................. 571.47 283.37 115.44 158.49 1128.77

Wisconsin .................................................................................................. 325.87 141.67 225.54 315.35 1008.43

Total ................................................................................................... 16548.70 7796.78 10977.80 13592.61 48915.89

TABLE VII–3.—2007 BUDGET MODELING EMISSIONS OF NOX

[Tons/day]

State EGU Non-EGU Area Highway Total

Alabama .................................................................................................... 224.26 159.58 335.69 386.24 1105.77

Arkansas ................................................................................................... 241.34 67.74 262.83 202.88 774.79

Connecticut ............................................................................................... 47.31 22.25 101.66 118.71 289.93

Delaware ................................................................................................... 40.59 15.18 36.83 57.67 150.27

District of Columbia .................................................................................. 2.45 1.69 26.75 15.46 46.35

Florida ....................................................................................................... 1193.66 143.06 351.44 875.17 2563.33

Georgia ..................................................................................................... 246.29 96.16 267.79 529.59 1139.83

Illinois ........................................................................................................ 278.01 278.58 477.65 529.99 1564.23

Indiana ...................................................................................................... 377.70 195.89 398.19 454.61 1426.39

Iowa .......................................................................................................... 318.51 79.17 176.64 227.15 801.47

Kansas ...................................................................................................... 278.16 200.10 373.76 194.01 1046.03

Kentucky ................................................................................................... 283.92 79.77 462.46 315.42 1141.57

Louisiana ................................................................................................... 370.72 797.24 717.26 274.46 2159.68

Maine ........................................................................................................ 7.31 62.32 37.87 109.26 216.76

Maryland ................................................................................................... 103.61 51.86 196.22 195.28 546.97

Massachusetts .......................................................................................... 112.86 43.88 208.53 157.66 522.93

Michigan .................................................................................................... 203.44 235.01 388.17 555.53 1382.15

Minnesota ................................................................................................. 269.07 74.35 166.35 353.51 863.28

Mississippi ................................................................................................. 239.02 180.66 370.67 229.32 1019.67

Missouri ..................................................................................................... 196.28 60.26 194.63 375.51 826.68

Nebraska ................................................................................................... 93.92 41.46 127.59 112.49 375.46

New Hampshire ........................................................................................ 118.61 8.03 34.64 86.94 248.22

New Jersey ............................................................................................... 83.04 83.57 241.65 268.82 677.08

New York .................................................................................................. 266.18 96.55 340.98 642.00 1345.71

North Carolina ........................................................................................... 252.33 127.56 214.94 498.25 1093.08

North Dakota ............................................................................................. 0.00 0.40 36.37 16.33 53.1

Ohio .......................................................................................................... 381.07 207.70 458.48 631.24 1678.49

Oklahoma .................................................................................................. 365.45 124.90 503.59 294.70 1288.64

Pennsylvania ............................................................................................. 357.05 314.54 343.61 499.34 1514.54

Rhode Island ............................................................................................. 10.81 2.34 18.98 38.89 71.02

South Carolina .......................................................................................... 151.97 127.09 164.62 337.58 781.26

South Dakota ............................................................................................ 49.91 0.64 31.29 48.65 130.49

Tennessee ................................................................................................ 191.00 240.31 451.78 461.03 1344.12

Texas ........................................................................................................ 1271.05 1114.13 712.99 974.78 4072.95

Vermont .................................................................................................... 0.20 1.04 12.50 59.13 72.87

Virginia ...................................................................................................... 176.69 73.05 379.47 544.69 1173.9

West Virginia ............................................................................................. 179.92 141.03 107.50 147.62 576.07

Wisconsin .................................................................................................. 124.49 77.21 192.28 284.20 678.18

Total ................................................................................................... 9108.20 5626.30 9924.65 12104.11 36763.26
25962 Federal Register / Vol. 63, No. 90 / Monday, May 11, 1998 / Proposed Rules

TABLE VII–4.—PERCENT REDUCTION BETWEEN 2007 CAA BASE CASE AND BUDGET N0X EMISSIONS FOR MODELING

[Tons/day]

State 2007 Base

case Budget Percentreduction

Alabama ................................................................................................................................................... 1712.61 1105.77 35.4

Arkansas ................................................................................................................................................... 805.81 774.79 3.9

Connecticut ............................................................................................................................................... 379.96 289.93 23.7

Delaware .................................................................................................................................................. 221.31 150.27 32.1

District of Columbia .................................................................................................................................. 53.79 46.35 13.8

Florida ....................................................................................................................................................... 2668.16 2563.33 3.9

Georgia ..................................................................................................................................................... 1765.93 1139.83 35.5

Illinois ........................................................................................................................................................ 2531.9 1564.23 38.2

Indiana ...................................................................................................................................................... 2427.97 1426.39 41.3

Iowa .......................................................................................................................................................... 833.82 801.47 3.9

Kansas ...................................................................................................................................................... 1072.05 1046.03 2.4

Kentucky ................................................................................................................................................... 1908.83 1141.57 40.2

Louisiana .................................................................................................................................................. 2221.51 2159.68 2.8

Maine ........................................................................................................................................................ 225.72 216.76 4.0

Maryland ................................................................................................................................................... 883.03 546.97 38.1

Massachusetts .......................................................................................................................................... 741.49 522.93 29.5

Michigan ................................................................................................................................................... 1965.62 1382.15 29.7

Minnesota ................................................................................................................................................. 908.32 863.28 5.0

Mississippi ................................................................................................................................................ 1073.12 1019.67 5.0

Missouri .................................................................................................................................................... 1330.46 826.68 37.9

Nebraska .................................................................................................................................................. 391.24 375.46 4.0

New Hampshire ........................................................................................................................................ 249.89 248.22 0.7

New Jersey ............................................................................................................................................... 952.25 677.08 28.9

New York .................................................................................................................................................. 1663.87 1345.71 19.1

North Carolina .......................................................................................................................................... 1701.85 1093.08 35.8

North Dakota ............................................................................................................................................ 55.11 53.1 3.6

Ohio .......................................................................................................................................................... 2803.99 1678.49 40.1

Oklahoma ................................................................................................................................................. 1327.88 1288.64 3.0

Pennsylvania ............................................................................................................................................ 2404.91 1514.54 37.0

Rhode Island ............................................................................................................................................ 87.12 71.02 18.5

South Carolina .......................................................................................................................................... 1224.89 781.26 36.2

South Dakota ............................................................................................................................................ 136.75 130.49 4.6

Tennessee ................................................................................................................................................ 2086.41 1344.12 35.6

Texas ........................................................................................................................................................ 4283.65 4072.95 4.9

Vermont .................................................................................................................................................... 78.05 72.87 6.6

Virginia ...................................................................................................................................................... 1599.42 1173.9 26.6

West Virginia ............................................................................................................................................ 1128.77 576.07 49.0

Wisconsin ................................................................................................................................................. 1008.43 678.18 32.7

Total .................................................................................................................................................. 48915.89 36763.26 24.8

TABLE VII–5.—LIST OF STATES IN EACH ANALYSIS REGION

Midwest ............................... Illinois, Indiana, Kentucky, Michigan, Missouri, Ohio, West Virginia, Wisconsin.

Southeast ............................ Alabama, Georgia, North Carolina, South Carolina, Tennessee, Virginia.

Northeast ............................ Connecticut, Delaware, District of Columbia, Maryland, Massachusetts, New Jersey, New York, Pennsylvania,

Rhode Island.

Non-SIP Call States ........... Arkansas, Florida, Iowa, Kansas, Louisiana, Maine, Minnesota, Mississippi, Nebraska, New Hampshire, North Dakota, Oklahoma, South Dakota, Texas, Vermont.

TABLE VII–6.—1-HR AIR QUALITY METRICS FOR MIDWEST REGION (GRID CELLS SELECTED BASED ON ‘‘MONITORED’’ AND ‘‘MODELED’’ NONATTAINMENT)

[Modeled values include Daily Max 1-hr for all 4 Episodes]

MO WI IL IN MI OH KY WV Total

Metric 1: Number of Grid Cell-Days with a Daily Max Ozone Value>=125 ppb

2007 Base ................................................................................................................... 4 0 10 3 23 3 0 0 43

2007 Budget ................................................................................................................ 2 0 2 0 4 3 0 0 11

Difference ......................................................................................................... ¥2 0 ¥8 ¥3 ¥19 0 0 0 ¥32

Percent ............................................................................................................. ¥50.00 0.00 ¥80.00 ¥100.00 ¥82.61 0.00 0.00 0.00 ¥74.42

Metric 2: Number of Grid Cell-Days with Ozone Reductions, by Magnitude of the Reduction

Magnitude of ozone reduction

2–5 ppb ....................................................................................................................... 0 0 0 0 0 0 0 0 0

5–10 ppb ..................................................................................................................... 1 0 1 1 1 1 0 0 5

10–15 ppb ................................................................................................................... 2 0 3 0 15 1 0 0 21

15–20 ppb ................................................................................................................... 0 0 3 0 7 1 0 0 11

20–25 ppb ................................................................................................................... 0 0 0 0 0 0 0 0 0

>25 ppb ....................................................................................................................... 0 0 2 2 0 0 0 0 4
Federal Register / Vol. 63, No. 90 / Monday, May 11, 1998 / Proposed Rules 25963

TABLE VII–6.—1-HR AIR QUALITY METRICS FOR MIDWEST REGION (GRID CELLS SELECTED BASED ON ‘‘MONITORED’’ AND ‘‘MODELED’’

NONATTAINMENT)—Continued

[Modeled values include Daily Max 1-hr for all 4 Episodes]

MO WI IL IN MI OH KY WV Total

Metric 3: Number of Grid Cells>=125 ppb, by Number of Days

Baseline 2007 MO WI IL IN MI OH KY WV Total

Number of Days >=125 ppb:

=1 day .................................................................................................................. 2 0 6 5 0 3 3 0 19

2–4 days ............................................................................................................... 1 0 2 9 0 0 0 0 12

5–9 days ............................................................................................................... 0 0 0 0 0 0 0 0 0

10–14 days ........................................................................................................... 0 0 0 0 0 0 0 0 0

>=15 days ............................................................................................................ 0 0 0 0 0 0 0 0 0

Total .................................................................................................................. 3 0 8 14 0 3 3 0 31

NOX SIP Call:

=1 day .................................................................................................................. 0 0 2 4 0 0 3 0 9

2–4 days ............................................................................................................... 1 0 0 0 0 0 0 0 1

5–9 days ............................................................................................................... 0 0 0 0 0 0 0 0 0

10–14 days ........................................................................................................... 0 0 0 0 0 0 0 0 0

>=15 days ............................................................................................................ 0 0 0 0 0 0 0 0 0

Total .................................................................................................................. 1 0 2 4 0 0 3 0 10

Difference (days) .............................................................................................. ¥2 0 ¥6 ¥10 0 ¥3 0 0 ¥21

Percent ............................................................................................................. ¥66.7 0.0 ¥75.0 ¥71.4 0.0 ¥100.0 0.0 0.0 ¥67.7

Metric 4: Percent Reduction in Areal Exposures to ozone >=125 ppb

July ’88 July ’91 July ’93 July ’95 All

episodes

MO ............................................................................................................................... 58.3 49.5 * * 40.4

WI ................................................................................................................................ * * * * *

IL .................................................................................................................................. 84.8 49.9 * 100.0 75.0

MI ................................................................................................................................. * * * 88.6 88.6

KY ................................................................................................................................ * * * * *

IN ................................................................................................................................. * * * 100.0 100.0

OH ............................................................................................................................... * * * * *

WV ............................................................................................................................... * * * * *

Total .................................................................................................................. 73.7 51.3 * 90.2 76.6

*No areas >=125 ppb

TABLE VII–7.—1-HR AIR QUALITY METRICS FOR SOUTHEAST REGION (GRID CELLS SELECTED BASED ON ‘‘MONITORED’’

AND ‘‘MODELED’’ NONATTAINMENT)

[Modeled values include Daily Max 1-hr for all 4 Episodes]

TN AL GA SC NC VA Total

Metric 1: Number of Grid Cell-Days with a Daily Max Ozone Value >+ 125 ppb

2007 Base ........................................................................................................................................................... 27 108 203 0 0 14 352

2007 Budget ........................................................................................................................................................ 13 53 117 0 0 13 196

Difference ................................................................................................................................................. ¥14 ¥55 ¥86 0 0 ¥1 ¥156

Percent ..................................................................................................................................................... ¥51.85 ¥50.93 ¥42.36 0.00 0.00 ¥7.14 ¥44.32

Metric 2: Number of Grid Cell-Days with Ozone Reductions, by Magnitude of the Reduction

Magnitude of ozone reduction

2–5 ppb ............................................................................................................................................................... 4 1 2 0 0 1 8

5–10 ppb ............................................................................................................................................................. 11 20 9 0 0 6 46

10–15 ppb ........................................................................................................................................................... 7 27 31 0 0 4 69

15–20 ppb ........................................................................................................................................................... 3 23 64 0 0 1 91

20–25 ppb ........................................................................................................................................................... 0 16 53 0 0 0 69

>25 ppb ............................................................................................................................................................... 0 21 44 0 0 0 65

Metric 3: Number of Grid Cells >= 125 ppb, by Number of Days

Baseline 2007 TN AL GA NC VA SC Total

Number of Days >= 125 ppb

= 1 day ......................................................................................................................................................... 7 9 5 0 0 0 21

2–4 days ...................................................................................................................................................... 6 14 15 0 1 0 36

5–9 days ...................................................................................................................................................... 1 8 17 0 2 0 28

10–14 days .................................................................................................................................................. 0 1 3 0 0 0 4

>= 15 days ................................................................................................................................................... 0 0 0 0 0 0 0

Total ......................................................................................................................................................... 14 32 40 0 3 0 89

NOx SIP Call:

= 1 day ......................................................................................................................................................... 6 6 8 0 0 0 20

2–4 days ...................................................................................................................................................... 2 11 10 0 1 0 24

5–9 days ...................................................................................................................................................... 0 3 11 0 2 0 16

10–14 days .................................................................................................................................................. 0 0 1 0 0 0 1

>=15 days .................................................................................................................................................... 0 0 0 0 0 0 0

Total ......................................................................................................................................................... 8 20 30 0 3 0 61

Difference (days) ...................................................................................................................................... ¥6 ¥12 ¥10 0 0 0 ¥28

Percent ..................................................................................................................................................... ¥42.9% ¥37.5% ¥25.0% 0.0% 0.0% 0.0% ¥31.5%

Metric 4: Percent Reduction in Areal Exposures to Ozone >= 125 ppb

July ’88 July ’91 July ’93 July ’95 All

Episodes

TN ....................................................................................................................................................................... 100.0 29.5 72.0 52.4 60.2

AL ........................................................................................................................................................................ 71.7 100.0 57.7 63.0 60.0
25964 Federal Register / Vol. 63, No. 90 / Monday, May 11, 1998 / Proposed Rules

TABLE VII–7.—1-HR AIR QUALITY METRICS FOR SOUTHEAST REGION (GRID CELLS SELECTED BASED ON ‘‘MONITORED’’

AND ‘‘MODELED’’ NONATTAINMENT)—Continued

[Modeled values include Daily Max 1-hr for all 4 Episodes]

TN AL GA SC NC VA Total

GA ....................................................................................................................................................................... 59.4 100.0 46.9 55.6 51.0

NC ....................................................................................................................................................................... * * * * * ................ ................

VA ....................................................................................................................................................................... 18.7% * * 58.2% 24.1% ................ ................

SC ....................................................................................................................................................................... * * * * * ................ ................

Total ......................................................................................................................................................... 50.1 89.7 51.0 57.5 53.0 ................ ................

*No areas >= 125 ppb.

TABLE VII–8.—1-HR AIR QUALITY METRICS FOR NORTHEAST REGION (GRID CELLS SELECTED BASED ON ‘‘MONITORED’’ AND ‘‘MODELED’’

NONATTAINMENT)

[Modeled values include Daily Max 1-hr for all 4 Episodes]

MD DC DE PA NJ NY CT RI MA Total

Metric 1: Number of Grid Cell-Days with a Daily Max Ozone Value >= 125 ppb

2007 Base ............................................................................................... 251 3 12 34 183 221 231 8 61 738

2007 Budget ............................................................................................ 111 3 3 17 54 154 141 2 13 381

Difference ...................................................................................... ¥140 0 ¥9 ¥17 ¥129 ¥67 ¥90 ¥6 ¥48 ¥357

Percent .......................................................................................... ¥55.78 0.00 ¥75.00 ¥50.00 ¥70.49 ¥30.32 ¥38.96 ¥75 ¥78.69 ¥48.37

Metric 2: Number of Grid Cell-Days with Ozone Reductions, by Magnitude of the Reduction

Magnitude of ozone reduction

2–5 ppb .................................................................................................... 7 0 0 3 5 26 16 0 3 60

5–10 ppb .................................................................................................. 27 1 0 7 12 63 58 2 7 177

10–15 ppb ................................................................................................ 43 0 0 14 41 89 115 6 27 335

15–20 ppb ................................................................................................ 91 0 1 6 90 24 25 0 15 252

20–25 ppb ................................................................................................ 40 0 6 2 19 1 0 0 2 70

>25 ppb ................................................................................................... 32 0 5 1 12 0 0 0 7 57

Metric 3: Number of grid Cells >= 125 ppb, by Number of Days

Baseline 2007 PA NY MD DC DE NJ CT MA RI Total

Number of Days >= 125 ppb:

=1 days ............................................................................................. 16 0 5 0 6 22 2 17 4 72

2–4 days ........................................................................................... 7 15 26 1 3 35 41 13 2 143

5–9 days ........................................................................................... 0 28 25 0 0 9 17 3 0 82

10–14 days ....................................................................................... 0 0 1 0 0 0 0 0 0 1

>=15 days ......................................................................................... 0 0 0 0 0 0 0 0 0 0

Total .............................................................................................. 23 43 57 1 9 66 60 33 6 298

NOX SIP Call:

=1 days ............................................................................................. 15 6 12 0 3 24 18 13 2 93

2–4 days ........................................................................................... 1 27 23 1 0 12 37 0 0 101

5–9 days ........................................................................................... 0 11 7 0 0 0 3 0 0 21

10–14 days ....................................................................................... 0 0 0 0 0 0 0 0 0 0

>=15 days ......................................................................................... 0 0 0 0 0 0 0 0 0 0

Total .............................................................................................. 16 44 42 1 3 36 58 13 2 215

Difference (days) .......................................................................... ¥7 1 ¥15 0 ¥6 ¥30 ¥2 ¥20 ¥4 ¥83

Percent .......................................................................................... ¥30.4 2.3 ¥26.3 0.0 ¥66.7 ¥45.5 ¥3.3 ¥60.6 ¥66.7 ¥27.9

Metric 4: Percent Reduction in Areal Exposures to Ozone >= 125 ppb

July ’88 July ’91 July ’93 July ’95 All

episodes

PA ............................................................................................................ 63.7 100.00 * 100.0 67.3

NY ............................................................................................................ 40.2 55.33 * 43.5 47.2

MD ........................................................................................................... 51.8 86.79 49.0 78.6 59.8

DC ............................................................................................................ 8.9 * * * 8.9

DE ............................................................................................................ 82.0 * * 100.0 84.5

NJ ............................................................................................................ 74.5 95.81 100.0 100.0 81.2

CT ............................................................................................................ 31.6 68.51 100.0 61.1 43.9

MA ........................................................................................................... 82.2 95.78 * 85.2 86.7

ME ........................................................................................................... 92.3 82.80 * * 89.3

Total .............................................................................................. 52.4 71.08 51.0 67.9 59.1

*No areas >= 125 ppb

TABLE VII–9.—SELECTED OTAG METRICS FOR 1-HR STANDARD

No.

corridor

Cn corridorSo.

corridor

Richmond Atlanta Nashville LouisCinci St. Louis Lk. MI

area Detroit Pittsburgh Charlotte

Peak 1-Hr Total—# OF GRID CELLS >124 PPB

July 4–11, 1988:

2007 Base Case ....................................... 337 484 522 148 38 56 71 10 46 54 27 157

2007 Budget ............................................. 147 314 214 27 19 14 22 4 0 34 1 19

Difference .............................................. ¥190 ¥170 ¥308 ¥121 ¥19 ¥42 ¥49 ¥6 ¥46 ¥20 ¥26 ¥138

Percent .................................................. ¥56.4% ¥35.1% ¥59.90% ¥81.8% ¥50.0% ¥75.0% ¥69.0% ¥60.0% ¥100.0% ¥37.0% ¥96.3% ¥87.9%

July 16–21, 1991:

2007 Base Case ....................................... 497 282 111 1 10 0 19 5 113 0 0 0

2007 Budget ............................................. 160 141 19 0 0 0 10 2 58 0 0 0

Difference .............................................. ¥337 ¥141 ¥92 ¥1 ¥10 0 ¥9 ¥3 ¥55 0 0 0

Percent .................................................. ¥67.8% ¥50.0% ¥82.9% ¥100.0% ¥100.0% 0.0% ¥47.4% ¥60.0% ¥48.7% 0.0% 0.0% 0.0%
Federal Register / Vol. 63, No. 90 / Monday, May 11, 1998 / Proposed Rules 25965

TABLE VII–9.—SELECTED OTAG METRICS FOR 1-HR STANDARD—Continued

No.

corridor

Cn

corridor

So.

corridor

Richmond Atlanta Nashville LouisCinci St. Louis Lk. MI

area Detroit Pittsburgh Charlotte

July 22–29, 1993:

2007 Base Case ....................................... 1 5 105 38 178 39 4 1 0 0 0 123

2007 Budget ............................................. 0 3 28 11 84 7 0 0 0 0 0 23

Difference .............................................. ¥1 ¥2 ¥77 ¥27 ¥94 ¥32 ¥4 ¥1 0 0 0 ¥100

Percent .................................................. ¥100.0% ¥40.0% ¥73.3% ¥71.1% ¥52.8% ¥82.1% ¥100.0% ¥100.0% 0.0% 0.0% 0.0% ¥81.3%

July 10–18, 1995:

2007 Base Case ....................................... 217 127 165 49 149 35 43 6 343 4 1 20

2007 Budget ............................................. 137 74 37 19 47 6 9 0 233 1 0 3

Difference .............................................. ¥80 ¥53 ¥128 ¥30 ¥102 ¥29 ¥34 ¥6 ¥110 ¥3 ¥1 ¥17

Percent ..................................................... ¥36.9% ¥41.7% ¥77.6% ¥61.2% ¥68.5% ¥82.9% ¥79.1% ¥100.0% ¥32.1% ¥75.0% ¥100.0% ¥85.0%

2007 Base Case ....................................... 217 127 165 49 149 35 43 6 343 4 1 20

2007 Budget ............................................. 137 74 37 19 47 6 9 00 233 1 0 3

Difference .............................................. ¥80 ¥53 ¥128 ¥30 ¥102 ¥29 ¥34 ¥6 ¥110 ¥3 ¥1 ¥17

Percent .................................................. ¥36.9% ¥41.7% ¥77.6% ¥61.2% ¥68.5% ¥82.9% ¥79.1% ¥100.0% ¥32.1% ¥75.0% ¥100.0% ¥85.0%

All Episodes:

2007 Base Case ....................................... 1052 898 903 236 375 130 137 22 502 58 28 300

2007 Budget ............................................. 444 532 298 57 150 27 41 6 291 35 1 45

Difference .............................................. ¥608 ¥366 ¥605 ¥179 ¥225 ¥103 ¥96 ¥16 ¥211 ¥23 ¥27 ¥255

Percent .................................................. ¥57.8% ¥40.8% ¥67.0% ¥75.8% ¥60.0% ¥79.2% ¥70.1% ¥72.7% ¥42.0% ¥39.7% ¥96.4% ¥85.0%

Peak 1-Hr Total—#  ́¢ ÉÆ•† ï°®®Ø • 140  ̈ ̈û

July 4–11, 1988:

2007 Base Case ....................................... 122 219 229 35 20 21 5 2 0 16 1 34

2007 Budget ............................................. 52 139 95 4 6 9 0 0 0 2 0 4

Difference .............................................. ¥70 ¥80 ¥134 ¥31 ¥14 ¥12 ¥5 ¥2 0 ¥14 ¥1 ¥30

Percent .................................................. ¥57.4% ¥36.5% ¥58.5% ¥88.6% ¥70.0% ¥57.1% ¥100.0% ¥100.0% 0.0% ¥87.5% ¥100.0% ¥88.2%

July 16–21, 1991:

2007 Base Case ....................................... 149 114 11 0 4 0 5 0 28 0 0 0

2007 Budget ............................................. 29 20 4 0 0 0 4 0 0 0 0 0

Difference .............................................. ¥120 ¥94 ¥7 0 ¥4 0 ¥1 0 ¥28 0 0 0

Percent .................................................. ¥80.5% ¥82.5% ¥63.6% 0.0% ¥100.0% 0.0% ¥20.0% 0.0% ¥100.0% 0.0% 0.0% 0.0%

July 22–29, 1993:

2007 Base Case ....................................... 0 0 21 14 99 8 0 0 0 0 0 38

2007 Budget ............................................. 0 0 4 0 38 1 0 0 0 0 0 5

Difference .............................................. 0 0 ¥17 ¥14 ¥61 ¥7 0 0 0 0 0 ¥33

Percent .................................................. 0.0% 0.0% ¥81.0% ¥100.0% ¥61.6% ¥87.5% 0.0% 0.0% 0.0% 0.0% 0.0% ¥86.8%

July 10–18, 1995:

2007 Base Case ....................................... 142 59 35 22 49 3 14 0 191 0 0 4

2007 Budget ............................................. 63 32 3 4 20 0 1 0 96 0 0 0

Difference .............................................. ¥79 ¥27 ¥32 ¥18 ¥29 ¥3 ¥13 0 ¥95 0 0 ¥4

Percent .................................................. ¥55.6% ¥45.8% ¥91.4% ¥81.8% ¥59.2% ¥100.0% ¥92.9% 0.0% ¥49.7% 0.0% 0.0% ¥100.0%

All Episodes:

2007 Base Case ....................................... 413 392 296 71 172 32 24 2 219 16 1 76

2007 Budget ............................................. 144 191 106 8 64 10 5 0 96 2 0 9

Difference .............................................. ¥269 ¥201 ¥190 ¥63 ¥108 ¥22 ¥19 ¥2 ¥123 ¥14 ¥1 ¥67

Percent .................................................. ¥65.1% ¥51.3% ¥64.2% ¥88.7% ¥62.8% ¥68.8% ¥79.2% ¥100.0% ¥56.2% ¥87.5% ¥100.0% ¥88.2%

Weighted Sum of Differences When the Base is > 124 ppb

July 4–11, 1988 ............................................... ¥13.8 ¥9.6 ¥18.5 ¥22.3 ¥18.3 ¥23.9 ¥17.4 ¥18.5 ¥13.8 ¥10 ¥24.5 ¥25.1

July 16–21, 1991 ............................................. ¥15.1 ¥13.7 ¥16.9 ¥10.4 ¥29 0 ¥13.3 ¥6.1 ¥10.9 0 0 0

July 22–29, 1993 ............................................. ¥5.7 ¥4.6 ¥15.8 ¥20 ¥21.3 ¥21.7 ¥26.2 ¥10.9 0 0 0 ¥22.6

July 10–18, 1995 ............................................. ¥15.8 ¥11.5 ¥16.8 ¥19 ¥21.5 ¥22.1 ¥27.4 ¥16 ¥12.6 ¥8.5 ¥40.8 ¥23.7

# Grid Cells with more than a 4 ppb Decrease when Base is > 124 ppb

July 4–11, 1988 ............................................... 330 386 496 144 38 55 67 10 46 51 27 156

Percent of Total ............................................... 97.9% 79.8% 95.0% 97.3% 100.0% 98.2% 94.4% 100.0% 100.0% 94.4% 100.0% 99.4%

July 16–21, 1991 ............................................. 496 276 104 1 10 0 16 3 104 0 0 0

Percent of Total ............................................... 99.8% 97.9% 93.7% 100.0% 100.0% 0.0% 84.2% 60.0% 92.0% 0.0% 0.0% 0.0%

July 22–29, 1993 ............................................. 1 3 102 38 178 37 4 1 0 0 0 123

Percent of Total ............................................... 100.0% 60.0% 97.1% 100.0% 100.0% 94.9% 100.0% 100.0% 0.0% 0.0% 0.0% 100.0%

July 10–18, 1995 ............................................. 217 111 161 48 149 35 43 6 326 4 1 20

Percent of Total ............................................... 100.0% 87.4% 97.6% 98.0% 100.0% 100.0% 100.0% 100.0% 95.0% 100.0% 100.0% 100.0%

All Episodes ..................................................... 1044 776 863 231 375 127 130 20 476 55 28 299

Percent of Total ............................................... 99.2% 86.4% 95.6% 97.9% 100.0% 97.7% 94.9% 90.9% 94.8% 94.8% 100.0% 99.7%

# Grid Cells with more than a 4 ppb Increase when Base is > 124 ppb

July 4–11, 1988 ............................................... 2 32 7 2 0 0 1 0 0 1 0 0

Percent of Total ............................................... 0.6% 6.6% 1.3% 1.4% 0.0% 0.0% 1.4% 0.0% 0.0% 1.9% 0.0% 0.0%

July 16–21, 1991 ............................................. 0 0 2 0 0 0 2 0 2 0 0 0

Percent of Total ............................................... 0.0% 0.0% 1.8% 0.0% 0.0% 0.0% 10.5% 0.0% 1.8% 0.0% 0.0% 0.0%

July 22–29, 1993 ............................................. 0 1 3 0 0 0 0 0 0 0 0 0

Percent of Total ............................................... 0.0% 20.0% 2.9% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0%

July 10–18, 1995 ............................................. 0 0 1 0 0 0 0 0 0 0 0 0

Percent of Total ............................................... 0.0% 0.0% 0.6% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0%
25966 Federal Register / Vol. 63, No. 90 / Monday, May 11, 1998 / Proposed Rules

TABLE VII–9.—SELECTED OTAG METRICS FOR 1-HR STANDARD—Continued

No.

corridor

Cn

corridor

So.

corridor

Richmond Atlanta Nashville LouisCinci St. Louis Lk. MI

area Detroit Pittsburgh Charlotte

All Episodes ..................................................... 2% 33% 13% 2% 0% 0% 3% 0% 2% 1% 0% 0%

Percent of Total ............................................... 0.2% 3.7% 1.4% 0.8% 0.0% 0.0% 2.2% 0.0% 0.4% 1.7% 0.0% 0.0%

TABLE VII–10.—8-HR AIR QUALITY METRICS FOR MIDWEST REGION (GRID CELLS SELECTED BASED ON ‘‘MONITORED’’ AND ‘‘MODELED’’

NONATTAINMENT)

MO WI IL IN MI OH KY WV Total

Metric 5: Number of Grid Cell-Days with an Average 2nd High Ozone Value >=85 ppb

Scenario

2007 Base ................................................................................................................... 2 0 7 31 21 39 43 7 150

2007 Budget ................................................................................................................ 2 0 1 3 1 2 7 0 16

Difference ......................................................................................................... 0 0 ¥6 ¥28 ¥20 ¥37 ¥36 ¥7 ¥134

Percent ............................................................................................................. 0.00 0.00 ¥85.71 ¥90.32 ¥95.24 ¥94.87 ¥83.72 ¥100.00 ¥89.33

Metric 6: Number of Grid Cell-Days with Ozone Reductions, by Magnitude of the Reduction

Magnitude of Ozone Reduction

2–5 ppb ....................................................................................................................... 1 0 0 1 1 0 2 0 5

5–10 ppb ..................................................................................................................... 1 0 5 2 12 16 6 0 42

10–15 ppb ................................................................................................................... 0 0 2 16 8 21 19 6 72

15–20 ppb ................................................................................................................... 0 0 0 9 0 2 12 1 24

20–25 ppb ................................................................................................................... 0 0 0 3 0 0 4 0 7

>25 ppb ....................................................................................................................... 0 0 0 0 0 0 0 0 0

TABLE VII–11.—8-HR AIR QUALITY METRICS FOR SOUTHEAST REGION (GRID CELLS SELECTED BASED ON ‘‘MONITORED’’ AND ‘‘MODELED’’

NONATTAINMENT)

TN AL GA SC NC VA Total

Metric 5: Number of Grid Cell-Days with an Average 2nd High Ozone Value≤=85ppb

Scenario

2007 Base ........................................................................................................................................................... 48 39 44 13 52 16 212

2007 Budget ........................................................................................................................................................ 10 12 17 1 4 3 47

Difference ................................................................................................................................................. ¥38 ¥27 ¥27 ¥12 ¥48 ¥13 ¥165

Percent ..................................................................................................................................................... ¥79.17 ¥69.23 ¥61.36 ¥92.31 ¥92.31 ¥81.25 ¥77.83

Metric 6: Number of Grid Cell-Days with Ozone Reductions, by Magnitude of the Reduction

Magnitude of Ozone Reduction

2–5 ppb ............................................................................................................................................................... 5 0 0 0 0 0 5

5–10 ppb ............................................................................................................................................................. 23 3 4 5 2 1 38

10–15 ppb ........................................................................................................................................................... 17 28 32 6 42 13 138

15–20 ppb ........................................................................................................................................................... 2 8 8 2 5 2 27

20–25 ppb ........................................................................................................................................................... 0 0 0 0 3 0 3

>25 ppb ............................................................................................................................................................... 0 0 0 0 0 0 0

TABLE VII–12.—8-HR AIR QUALITY METRICS FOR NORTHEAST REGION (GRID CELLS SELECTED BASED ON ‘‘MONITORED’’ AND ‘‘MODELED’’

NONATTAINMENT)

MD DC DE PA NJ NY CT RI MA Total

Metric 5: Number of Grid Cell-Days with an Average 2nd High Ozone Value>=85 ppb

Scenario

2007 Base ............................................................................................... 84 1 30 73 99 45 29 0 11 257

2007 Budget ............................................................................................ 40 0 1 4 37 33 11 0 6 91

Difference ...................................................................................... ¥44 ¥1 ¥29 ¥69 ¥62 ¥12 ¥18 0 ¥5 ¥166

Percent .......................................................................................... ¥52.38 ¥100.00 ¥96.67 ¥94.52 ¥62.63 ¥26.67 ¥62.07 0.00 ¥45.45 ¥65

Metric 6: Number of Grid Cell-Days with Ozone Reductions, by Magnitude of the Reduction

Magnitude of Ozone Reduction

2–5 ppb .................................................................................................... 1 0 0 1 1 6 1 0 1 11

5–10 ppb .................................................................................................. 18 1 3 19 17 34 28 0 9 129

10–15 ppb ................................................................................................ 57 0 13 46 75 0 0 0 1 192

15–20 ppb ................................................................................................ 7 0 14 7 6 0 0 0 0 34

20–25 ....................................................................................................... 0 0 0 0 0 0 0 0 0 0

>25 ppb ................................................................................................... 0 0 0 0 0 0 0 0 0 0

TABLE VII–13.—SELECTED OTAG METRICS FOR 8–HR STANDARD

No.

corridor

Cn.

corridor

So.

corridor

Richmond Atlanta Nashville LouisCinci St. Louis Lk. MI

Area Detroit Pittsburgh Charlotte

Peak 8–Hr Total—# of Grids > 84 ppb

July 4–11, 1988:

2007 Base Case ....................................... 1624 1959 1696 580 154 485 1653 196 853 478 850 1195

2007 Budget ............................................. 1132 1256 1115 313 68 139 447 32 435 253 197 450

Difference .............................................. ¥492 ¥703 ¥581 ¥267 ¥86 ¥346 ¥1206 ¥164 ¥418 ¥225 ¥653 ¥745

Percent .................................................. ¥30.3% ¥35.9% ¥34.3% ¥46.0% ¥55.8% ¥71.3% ¥73.0% ¥83.7% ¥49.0% ¥47.1% ¥76.8% ¥62.3%
Federal Register / Vol. 63, No. 90 / Monday, May 11, 1998 / Proposed Rules 25967

TABLE VII–13.—SELECTED OTAG METRICS FOR 8–HR STANDARD—Continued

No.

corridor

Cn.

corridor

So.

corridor

Richmond Atlanta Nashville LouisCinci St. Louis Lk. MI

Area Detroit Pittsburgh Charlotte

July 16–21, 1991:

2007 Base Case ....................................... 1333 1034 1058 112 56 93 875 129 615 172 605 71

2007 Budget ............................................. 1019 573 552 12 21 10 198 37 512 51 81 0

Difference .............................................. ¥314 ¥461 ¥506 ¥100 ¥35 ¥83 ¥677 ¥92 ¥103 ¥121 ¥524 ¥71

Percent .................................................. ¥23.6% ¥44.6% ¥47.8% ¥89.3% ¥62.5% ¥89.2% ¥77.4% ¥71.3% ¥16.7% ¥70.3% ¥86.6% ¥100.0%

July 22–29, 1993:

2007 Base Case ....................................... 161 204 610 206 855 395 545 56 79 23 59 1562

2007 Budget ............................................. 88 134 315 92 374 125 78 17 24 2 0 387

Difference .............................................. ¥73 ¥70 ¥295 ¥114 ¥481 ¥270 ¥467 ¥39 ¥55 ¥21 ¥59 ¥1175

Percent .................................................. ¥45.3% ¥34.3% ¥48.4% ¥55.3% ¥56.3% ¥68.4% ¥85.7% ¥69.6% ¥69.6% ¥91.3% ¥100.0% ¥75.2%

July 10–18, 1995:

2007 Base Case ....................................... 653 714 1489 527 693 708 1072 124 994 311 468 754

2007 Budget ............................................. 437 321 642 142 260 160 215 52 712 150 20 96

Difference .............................................. ¥216 ¥393 ¥847 ¥385 ¥433 ¥548 ¥857 ¥72 ¥282 ¥161 ¥448 ¥658

Percent .................................................. ¥33.1% ¥55.0% ¥56.9% ¥73.1% ¥62.5% ¥77.4% ¥79.9% ¥58.1% ¥28.4% ¥51.8% ¥95.7% ¥87.3%

All Episodes:

2007 Base Case ....................................... 3771 3911 4853 1425 1758 1681 4145 505 2541 984 1982 3582

2007 Budget ............................................. 2676 2284 2624 559 723 434 938 138 1683 456 298 933

Difference .............................................. ¥1095 ¥1627 ¥2229 ¥866 ¥1035 ¥1247 ¥3207 ¥367 ¥858 ¥528 ¥1684 ¥2649

Percent .................................................. ¥29.0% ¥41.6% ¥45.9% ¥60.8% ¥58.9% ¥74.2% ¥77.4% ¥72.7% ¥33.8% ¥53.7% ¥85.0% ¥74.0%

Peak 8–Hr Total—Grid Cells > 100 ppb

July 4–11, 1988:

2007 Base Case ....................................... 817 862 975 302 64 149 383 25 320 139 215 458

2007 Budget ............................................. 418 555 413 96 26 32 50 6 92 74 13 75

Difference .............................................. ¥399 ¥307 ¥562 ¥206 ¥38 ¥117 ¥333 ¥19 ¥228 ¥65 ¥202 ¥383

Percent .................................................. ¥48.8% ¥35.6% ¥57.6% ¥68.2% ¥59.4% ¥78.5% ¥86.9% ¥76.0% ¥71.3% ¥46.8% ¥94.0% ¥83.6%

July 16–21, 1991:

2007 Base Case ....................................... 868 501 448 13 21 1 190 22 302 18 62 0

2007 Budget ............................................. 511 305 109 0 4 0 22 7 204 1 0 0

Difference .............................................. ¥357 ¥196 ¥339 ¥13 ¥17 ¥1 ¥168 ¥15 ¥98 ¥17 ¥62 0

Percent .................................................. ¥41.1% ¥39.1% ¥75.7% ¥100.0% ¥81.0% ¥100.0% ¥88.4% ¥68.2% ¥32.5% ¥94.4% ¥100.0% 0.0%

July 22–29, 1993:

2007 Base Base Case ............................. 34 59 212 85 322 97 71 4 0 0 0 399

2007 Budget ............................................. 11 30 63 25 151 23 1 0 0 0 0 81

Difference .............................................. ¥23 ¥29 ¥149 ¥60 ¥171 ¥74 ¥70 ¥4 0 0 0 ¥318

Percent .................................................. ¥67.6% ¥49.2% ¥70.3% ¥70.6% ¥53.1% ¥76.3% ¥98.6% ¥100.0% 0.0% 0.0% 0.0% ¥79.7%

July 10–18, 1995:

2007 Base Case ....................................... 328 255 544 105 259 159 225 27 553 60 15 98

2007 Budget ............................................. 230 139 139 34 112 28 27 1 423 17 1 6

Difference .............................................. ¥98 ¥116 ¥405 ¥71 ¥147 ¥131 ¥198 ¥26 ¥130 ¥43 ¥14 ¥92

Percent .................................................. ¥29.9% ¥45.5% ¥74.4% ¥67.6% ¥56.8% ¥82.4% ¥88.0% ¥96.3% ¥23.5% ¥71.7% ¥93.3% ¥93.9%

All Episodes:

2007 Base Case ....................................... 2047 1677 2179 505 666 406 869 78 1175 217 292 955

2007 Budget ............................................. 1170 1029 724 155 293 83 100 14 719 92 14 162

Difference .............................................. ¥877 ¥648 ¥1455 ¥350 ¥373 ¥323 ¥769 ¥64 ¥456 ¥125 ¥278 ¥793

Percent .................................................. ¥42.8% ¥38.6% ¥66.8% ¥69.3% ¥56.0% ¥79.6% ¥88.5% ¥82.1% ¥38.8% ¥57.6% ¥95.2% ¥83.0%

VIII. Impact on Small Entities

The Regulatory Flexibility Act, 5

U.S.C. 601 et seq. (RFA), provides that

whenever an agency is required to

publish a general notice of proposed

rulemaking, it must prepare and make

available a 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.’’

Id., section 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, e.g., MidTex Electric Cooperative, Inc. v. FERC,

773 F.2d 327 (D.C. Cir. 1985) (agency’s

certification need only consider the

rule’s impact on regulated entities and

not indirect impact on small entities not

regulated).

In the proposed rulemaking, which

EPA published by notice dated

November 7, 1997, 62 FR 60318, EPA

noted that the proposed rule would not

directly regulate small entities. Instead,

the proposed rule would require States

to develop, adopt, and submit SIP

revisions that would achieve the

necessary NOX emission reductions, and

would leave to the States the task of

determining how to obtain those

reductions, including which entities to

regulate. The EPA also noted, in the

proposed rule, that 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, at the time of the

proposal, predict the effect of the rule

on small entities.

The purposes of the RFA, the RFA’s

statutory requirements for regulatory

flexibility analyses, and the caselaw all

shed light on the meaning of the term

‘‘impact’’ as used in the RFA. These

sources indicate that a rule can have an

‘‘impact’’ of concern under the RFA

only with respect to sources subject to

the requirements of the rule.
25968 Federal Register / Vol. 63, No. 90 / Monday, May 11, 1998 / Proposed Rules

The RFA’s ‘‘Findings and Purposes’’

section states,

It is the purpose of this Act to establish as

a principle of regulatory issuance that

agencies shall endeavor, consistent with the

objective of the rule and of applicable

statutes, to fit regulatory and information

requirements to the scale of the businesses,

organizations, and governmental

jurisdictions subject to regulation.

Pub. L. 96–354, section 2(b). This

statement of purpose indicates that

Congress intended the RFA to ensure

that agencies tailored the requirements

of their regulations to the resources and

capabilities of entities ‘‘subject to [such]

regulation.’’ Other provisions of the

RFA reflect this statement of purpose.

For example, RFA sections 603 and 604

require that the initial and final

regulatory flexibility analyses identify

the types and estimate the numbers of

small entities ‘‘to which the proposed

rule will apply’’ (sections 603(b)(3) and

604(a)(3)); and other RFA provisions

make clear that the regulatory flexibility

analyses are to focus on how to

minimize rule requirements for small

entities (sections 603(c)(1) and (4),

605(a)(5)). Taken as a whole, these

provisions suggest that agencies should

undertake the RFA analyses only with

respect to rules to which small entities

are subject.

Two Federal court cases support this

interpretation of ‘‘impact’: Mid-Tex Elec.

Co-op v. FERC, 773 F.2d 327, 342 (D.C.

Cir. 1985), summarized above, and

United Distribution Companies v. FERC,

88 F.3d 1105 (D.C. Cir. 1996). In United

Distribution Companies, the court stated

that the Mid-Tex court—

* * * conducted an extensive analysis of

the RFA provisions governing when a

regulatory flexibility analysis is required and

concluded that no analysis is necessary when

an agency determines ‘‘that the rule will not

have a significant economic impact on a

substantial number of small entities that are

subject to the requirements of the rule.’’

Id. at 1170 (quoting Mid-Tex court,

emphasis added by United Distribution

court). For a more detailed analysis by

EPA of the RFA, see ‘‘Final Rule:

National Ambient Air Quality Standards

for Ozone,’’ 62 FR 38856, 38888 (July

18, 1997).

For the reasons indicated above, EPA

certified that the proposed rule would

‘‘not have, if promulgated, a significant

economic impact on a substantial

number of small entities.’’ The Agency

received a number of comments on this

certification, including several

challenging the certification as improper

under the RFA. The EPA is currently

considering these comments and will

respond to them in light of the

rulemaking record after comments are

received on this supplemental proposal.

Today’s supplemental proposal does

not contain anything that would

adversely affect small entities. The SIP

criteria and emissions reporting

requirements proposed in today’s action

would apply only to States, and would

not, by themselves, subject any other

entities to any regulation. The NOX

budget trading program is a

recommendation to States, but not a

requirement, and thus does not subject

any entities to any requirements. In

addition, the trading program, if

adopted by a State, would provide

sources subject to the State NOX

controls additional flexibility in meeting

SIP requirements. Thus, the trading

program would have a beneficial effect

on State-regulated sources, including

small entities subject to those State

requirements. Accordingly, EPA

certifies that this supplemental proposal

will not, if promulgated, have a

significant economic impact on a

substantial number of small entities.

As noted in Section VI, Interaction

with Title IV NOX Rule, today’s

supplemental proposal includes, in

addition to provisions directly related to

the NOX SIP call, a revision to the 40

CFR Part 76, which implements the

NOX requirements of the acid rain

provisions in Title IV of the CAA

Amendments and which applies

directly to sources. The revision is

designed to lessen the administrative

requirements imposed on sources

affected by the acid rain program that

are in States that adopt a NOX cap-andtrade program. Because the only impact

of this revision will be to ease

administrative requirements, it will not

have any adverse effect on any small

entity that may be subject to the rule’s

requirements. Accordingly, I certify that

this part of today’s proposed rule will

not have a significant economic effect

on a substantial number of small

entities.

IX. Unfunded Mandates Reform Act

Title II of the Unfunded Mandates

Reform Act of 1995 (UMRA), Public

Law 104–4, establishes requirements for

Federal agencies to assess the effects of

their regulatory actions on State, local,

and tribal governments and the private

sector. Under section 202 of the UMRA,

2 U.S.C. 1532, EPA generally must

prepare a written statement, including a

cost-benefit analysis, for any proposed

or final 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.

Under section 203 of UMRA, 2 U.S.C.

1533, before EPA establishes any

regulatory requirements ‘‘that might

significantly or uniquely affect small

governments’’ EPA must have

developed a small government agency

plan. The plan must provide for

notifying potentially affected small

governments; enabling officials of

affected small governments to have

meaningful and timely input in the

development of EPA regulatory

proposals with significant Federal

intergovernmental mandates; and

informing, educating, and advising

small governments on compliance with

the regulatory requirements.

Under section 204 of UMRA, 2 U.S.C.

1534, if an agency proposes a rule that

contains a ‘‘significant Federal

intergovernmental mandate[], the

agency must develop a process to permit

elected officials of State, local, and

tribal governments to provide input into

the development of the proposal.

The EPA addressed these issues, in

the proposed rulemaking as to the

proposed NOX SIP call. However, as

noted in Section VI, Interaction with

Title IV NOX Rule, today’s supplemental

proposal includes, in addition to

provisions directly related to the

proposed NOX SIP call, a revision to the

40 CFR Part 76, which implements the

NOX requirements of the acid rain

provisions in Title IV of the CAA

Amendments and which applies

directly to sources. The revision is

designed to lessen the administrative

requirements imposed on sources

affected by the acid rain program that
Federal Register / Vol. 63, No. 90 / Monday, May 11, 1998 / Proposed Rules 25969

are in States that adopt a NOX cap-andtrade program. Because the only impact

of this part of the rule will be to ease

administrative requirements, it will not

impose costs that would trigger the

requirements of UMRA sections 202,

204, or 205. For the same reason, this

part of the rule would not result in

regulatory requirements that might

significantly affect small governments;

moreover, this part of the proposed rule

would not impose requirements unique

to small governments. Thus, the

requirements of section 203 (2 U.S.C.

1533) do not apply to the revisions to

40 CFR Part 76.

X. Paperwork Reduction Act

The information collection

requirements in this proposed rule have

been submitted for approval to the

Office of 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. 1857.01) and a copy may be

obtained from Sandy Farmer, OPPE

Regulatory Information Division, U.S.

Environmental Protection Agency

(2137), 401 M St. SW, Washington, DC

20460 or by calling (202) 260–2740.

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

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 proposed

reporting requirements resides in

section 110(a) and 301(a) of the CAA.

Emissions data being requested in

today’s proposal would not be

considered confidential by EPA. Certain

process data may be identified as

sensitive by a State and are then treated

as ‘‘State-sensitive’’ 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: 282.

Estimated Annual Cost per

Respondent: $7,942.68.

Estimated Total Annual Hour Burden:

6,486.

Estimated Total Annualized Cost:

$182,682.00.

There are no additional capital or

operating and maintenance costs

associated with the reporting

requirements of the proposed 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, OPPE

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 June 22,

1998. Include the ICR number in any

correspondence.

XI. 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 Act in

a way that could affect future actions

regulating the transport of pollutants. In

addition, the SIP Call, as proposed,

would require 22 States and the District

of Columbia to establish emissions

budgets for NOX. The 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 SIP Call. Finally, EPA plans to

establish in the final rule uniform

approvability criteria that would be

applied to all States subject to the 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 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 promulgated in

the Federal Register.

XII. Regulatory Analysis

Under Executive Order 12866 (58 FR

51735, October 4, 1993), the Agency

must determine whether the regulatory

action is ‘‘significant’’ and therefore

subject to Office of Management and

Budget (OMB) review and the

requirements of the Executive Order.

The Order defines ‘‘significant

regulatory action’’ as one that is likely

to result in a rule that may:

(1) Have an annual effect on the

economy of $100 million or more or

adversely affect in a material way the

economy, a sector of the economy,

productivity, competition, jobs, the

environment, public health or safety, or
25970 Federal Register / Vol. 63, No. 90 / Monday, May 11, 1998 / Proposed Rules

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.

As EPA indicated in the proposed

rulemaking, this action is a ‘‘significant

regulatory action’’ because it would

have an annual effect on the economy

of approximately $2 billion. 62 FR

60318, 60373. Accordingly, the notice of

proposed rulemaking was submitted to

OMB for review. For the same reason,

today’s supplemental notice of proposed

rulemaking was submitted to OMB for

review. 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.

List of Subjects

40 CFR Part 51

Environmental protection,

Administrative practice and procedure,

Air pollution control, Carbon monoxide,

Intergovernmental relations, Nitrogen

dioxide, Ozone, Particulate matter,

Reporting and recordkeeping

requirements, Sulfur oxides,

Transportation, Volatile organic

compounds.

40 CFR Part 76

Environmental protection, Acid rain

program, Air pollution control, Nitrogen

dioxide, Reporting and recordkeeping

requirements.

40 CFR Part 96

Environmental protection,

Administrative practice and procedure,

Air pollution control, Nitrogen dioxide,

Reporting and recordkeeping

requirements.

Dated: April 28, 1998.

Carol M. Browner,

Administrator.

For the reasons set forth in the

preamble, parts 51, 76, and 96 of

chapter I of title 40 of the Code of

Federal Regulations are proposed to be

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, 7410, 7411,

7412, 7413, 7414, 7470–7479, 7501–7508,

7601, and 7602.

Subpart G—Control Strategy

2. Subpart G is amended to add

§§ 51.121 and 51.122 to read as follows:

§ 51.121 Requirements for state

implementation plan revisions relating to

budgets for emissions of oxides of

nitrogen.

(a) The EPA Administrator finds that

the State implementation plans (SIPs)

for the States listed in paragraph (c) of

this section are substantially inadequate

to comply with the requirements of

section 110(a)(2)(D) of the Clean Air

Act, 42 U.S.C. 7410(a)(2)(D), and to

mitigate adequately the interstate

pollutant transport described in section

184 of the Clean Air Act, 42 U.S.C.

7511c, with respect to nonattainment

areas under the 1-hour ozone national

ambient air quality standards (NAAQS),

to the extent that those SIPs do not

provide for compliance with a budget of

emissions of nitrogen oxides (‘‘NOX

budget’’) as described in paragraph (e) of

this section. To cure such inadequacy,

each of the States listed in paragraph(c)

of this section must submit to EPA a SIP

revision that provides for compliance

with such NOX budget and associated

SIP provisions described in this section.

(b) The EPA Administrator

determines that the States listed in

paragraph (c) of this section must

submit SIP revisions under section

110(a)(1) of the Clean Air Act, 42 U.S.C.

7410(a)(1), that provide for compliance

with a NOX budget, as described in

paragraph (e) of this section and

associated SIP provisions described in

this section, to comply with the

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

the Clean Air Act, 42 U.S.C.

7410(a)(2)(D), with respect to

nonattainment areas under the 8-hour

ozone NAAQS.

(c) The States subject to paragraphs (a)

and (b) of this section are: 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 paragraphs (a) and (b) of this

section must be submitted 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 allowed from all sources in

that State, as indicated in paragraph

(e)(4) of this section with respect to that

State.

(2) The SIP must provide for

compliance with the NOX budget during

each ozone season, which includes May

1 through September 30 of the year 2007

and each subsequent year.

(3) The SIP must require

implementation of its control measures

by no later than September 30, 2002.

(4) The State-by-State amounts of the

NOX budget are as follows:

State Budget

Alabama .................................... 155,617

Connecticut ............................... 39,909

Delaware ................................... 21,010

District of Columbia .................. 7,000

Georgia ..................................... 159,013

Illinois ........................................ 218,679

Indiana ...................................... 200,345

Kentucky ................................... 158,360

Maryland ................................... 73,628

Massachusetts .......................... 73,575

Michigan .................................... 199,238

Missouri ..................................... 116,246

New Jersey ............................... 93,464

New York .................................. 185,537

North Carolina ........................... 153,106

Ohio .......................................... 236,443

Pennsylvania ............................. 207,250

Rhode Island ............................. 10,132

South Carolina .......................... 109,267

Tennessee ................................ 187,250

Virginia ...................................... 162,375

West Virginia ............................. 81,701

Wisconsin .................................. 95,902

Total ................................... 2,945,046

(f) Each SIP revision must set forth

control measures to meet the NOX

budget 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.
Federal Register / Vol. 63, No. 90 / Monday, May 11, 1998 / Proposed Rules 25971

(2) Should a State elect to impose

control measures on NOX sources

serving electric generators with a

nameplate capacity greater than 25

MWe or boilers with a maximum design

heat input greater than 250 mmBtu/hr as

a means of meeting its NOX budget, then

those measures must either:

(i) Impose a NOX mass emissions cap

on each source;

(ii) Impose a NOX emission rate limit

on each source and assume maximum

operating capacity for every such source

for purposes of estimating mass NOX

emissions; or

(iii) Impose any other regulatory

requirement which the State has

demonstrated to EPA provides

equivalent or greater assurance than

options in paragraphs (e)(2) (i) or (ii) of

this section that the State will meet its

NOX budget.

(g)(1) Each SIP revision must

demonstrate that the measures, rules,

and regulations contained in it are

adequate to provide for the timely

compliance with the 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 point, area, and mobile

sources in the year 2007 absent the

control measures specified in the SIP

submission. The State must use the

same baseline inventory that EPA used

in calculating the State’s NOX budget.

(ii) Each revision must contain a

summary of NOX mass emissions in

2007 projected to result from

implementation of each of the new

control measures and from all NOX

sources together following

implementation of such control

measures. The summary must assume

the same NOX mass emissions for

mobile sources assumed by EPA in

calculating the State’s budget, unless the

State has adopted measures more

stringent than the Federal measures

incorporated into the budget

calculation. The State must provide EPA

with a summary of the computations,

assumptions, and judgments used to

determine the degree of reduction of

projected emissions that will result from

the implementation of the control

measures.

(iii) Each revision must identify the

sources of the data used in the

projection of emissions.

(h) Each revision must comply with

§ 51.116 (regarding data availability).

(1) Each revision must provide for

monitoring the status of compliance

with any rules and regulations adopted

to meet the NOX budget. Specifically,

the revision must meet the following

requirements:

(i) 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—

(A) Information on the amount of NOX

emissions from the stationary sources;

and

(B) 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;

(ii) The revision must comply with

§ 51.212 of this part (regarding testing,

inspection, enforcement, and

complaints);

(iii) If the revision contains any

transportation control measures, then

the revision must comply with § 51.213

(regarding transportation control

measures);

(iv) If the revision contains measures

to control NOX sources serving electric

generators with a nameplate capacity

greater than 25 MWe or greater or

boilers with a maximum design heat

input greater than 250 mmBtu/hr, then

the revision must require such sources

to use a continuous emissions

monitoring system.

(2) [Reserved]

(i) [Reserved]

(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 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

Act.

(l)(1) A revision may assign legal

authority to local agencies in

accordance with section 51.232.

(2) Each revision must comply with

section 51.240 (regarding general plan

requirements).

(m) Each revision shall contain legally

enforceable compliance schedules

setting forth September 30, 2002 as the

date by which all sources or categories

of such sources must be in compliance

with any applicable requirement of the

SIP revision.

(n) Each revision must comply with

section 51.280 (regarding resources).

(o) For purposes of the SIP revisions

required by this section, EPA may make

a finding under section 179(a)(1)

through (4) of the Act, 42 U.S.C.

7509(a)(1)-(4), starting the sanctions

process set forth in section 179(a) of the

Act. Any such finding will be deemed

a finding under section 52.31(c) and

sanctions will be imposed in accordance

with the order of sanctions and the

terms for such sanctions established in

section 52.31.

(p) Each revision must provide for

State compliance with the reporting

requirements set forth in section 51.122

of this part.

§ 51.122 Emissions reporting

requirements for SIP revisions relating to

budgets for NOx emissions.

(a) For its transport SIP revision under

section 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 that the

emissions budget set forth in section

51.121(e)(4) is being met.

(1) Annual reporting. Each revision

must provide for annual reporting of

NOX emissions data from all of the

following sources and source categories:

(i) All NOX sources within the State

which the State chooses to regulate

specifically for the purpose of meeting

the NOX budgets submitted under

section 51.121(e)(4). This would include

all NOX sources within the State which

are subject to measures included by the

State in its transport SIP revision

submitted under section 51.121. On

road and nonroad mobile sources are

not included unless controls greater

than those Federally mandated are

required for these sources.

(ii) The direct reporting of data from

sources to EPA used for compliance
25972 Federal Register / Vol. 63, No. 90 / Monday, May 11, 1998 / Proposed Rules

with the requirements of a trading

program meeting the requirements of 40

CFR part 96 and/or direct reporting of

data from sources to EPA used for

meeting the monitoring and reporting

requirements of subpart H of 40 CFR

part 75 can be used to satisfy this

requirement.

(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 section 51.116 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 FIPS code.

(iii) County FIPS 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) Annual emissions.

(xii) Ozone Season emissions.

(xiii) 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) Winter throughput (%).

(viii) Spring throughput (%).

(ix) Summer throughput (%).

(x) Fall throughput (%).

(xi) Work weekday emissions.

(xii) Emission factor.

(xiii) Source of emission factor.

(xiv) Hr/day in operation.

(xv) Operations Start time (hour).

(xvi) Day/wk in operation.

(xvii) Wk/yr 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) Hr/day in operation.

(xviii) Day/wk in operation.

(xix) Wk/yr in operations.

(2) The triennial and 2007 inventories

must contain at a minimum all the data

required in paragraph (d)(1) of this

section.

(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) Emission factor.

(v) Source of emission factor.

(vi) Activity (VMT by Roadway Class).

(vii) Source of activity data.

(viii) Pollutant code.

(ix) Summer work weekday

emissions.

(x) Ozone season emissions.

(xi) 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 the

year 2003.

(2) Triennial reports are to begin with

data for the year 2002.

(3) Year 2007 data are to be submitted

for the year 2007.

(4) States must submit data for a

required year by 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

the location given in paragraph (h)(5) of

this section. 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.

This option will be available to any

source in a State that is both

participating in a trading program

meeting the requirements of part 96 of

this chapter and that has agreed to

accept data in this format. The EPA will
Federal Register / Vol. 63, No. 90 / Monday, May 11, 1998 / Proposed Rules 25973

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

national ambient air quality standard.

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

reduction 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) County/parish/reservation (FIPS).

Federal Information Placement System

(FIPS). FIPS is 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.

(8) Day/wk in operations. Days per

week that the emitting process operates.

(9) Emission factor. Ratio relating

emissions of a specific pollutant to an

activity or material throughput level.

(10) Exit gas flow rate. Numeric value

of stack gas flow rate.

(11) Exit gas temperature. Numeric

value of an exit gas stream temperature.

(12) Exit gas velocity. Numeric value

of an exit gas stream velocity.

(13) Fall throughput (%). Portion of

throughput for the three 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).

(14) Federal ID code (plant). Unique

codes for a plant or facility, containing

one or more pollutant-emitting sources.

(15) Federal ID code (point). Unique

codes for the point of generation of

emissions, typically a physical piece of

equipment.

(16) Federal ID code (stack number).

Unique codes for the point where

emissions from one or more processes

are released into the atmosphere.

(17) 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.

(18) 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.

(19) Hr/day in operations. Hours per

day that the emitting process operates.

(20) Maximum design rate. Maximum

fuel use rate based on the equipment’s

or process’ physical size or operational

capabilities.

(21) Maximum nameplate capacity. A

measure of the size of a generator, and

is put on the unit’s nameplate by the

manufacturer. The data element is

reported in MW or KW.

(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. A non-mobile source

which emits less NOX per year than this

amount 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 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 emission reduction efficiency of a

secondary control device, which shows

the amount of reduction 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 three

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) State/providence/territory (FIPS).

Federal Information Placement System

(FIPS). FIPS is 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.

(37) Summer throughput (%). Portion

of throughput or activity for the three

summer months (June, July, August).

See the definition of Fall Throughput.

(38) Summer work weekday

emissions. Average day’s emissions for

a typical day.

(39) VMT by Roadway Class. VMT

stands for vehicle miles traveled and 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.

(40) Winter throughput (%). Portion of

throughput or activity for the three

winter months (December, January,

February). See the definition of Fall

Throughput.

(41) Week/year in operation. Weeks

per year that the emitting process

operates.

(42) Work Weekday. Any day of the

week except Saturday or Sunday.
25974 Federal Register / Vol. 63, No. 90 / Monday, May 11, 1998 / Proposed Rules

(43) X coordinate (latitude). East-west

geographic coordinate of an object.

(44) Y coordinate (longitude). Northsouth geographic coordinate of an

object.

PART 76—ACID RAIN NITROGEN

OXIDES EMISSION REDUCTION

PROGRAM

3. The authority citation for part 76

continues to read as follows:

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

4. Section 76.16 is added to read as

follows:

§ 76.16 Alternative compliance.

(a)(1) A State or group of States may

submit a petition requesting that the

Administrator, on his or her own

motion, may:

(i) Require the owners or operators of

the Group 1, Phase II coal-fired utility

units with a tangentially fired boiler or

a dry bottom wall fired boiler in the

State or the group of States to be subject

to the applicable emission limitations

for NOX in § 76.5, in lieu of the

applicable emission limitations for NOX

in § 76.7; and

(ii) Provide that the owners or

operators of the Group 2 coal-fired

utility units with a cell burner boiler,

cyclone boiler, wet bottom boiler, or

vertically fired boiler in the State or the

group of States are not subject to the

applicable emission limitations for NOX

in § 76.6.

(2) A petition under paragraph (a)(1)

of this section must demonstrate that

the requirements in paragraphs (b)(1)

and (2) of this section are met.

(3) A petition under paragraph (a)(1)

of this section may be submitted, but

may not be approved by the

Administrator, before the State

implementation plan or Federal

implementation plan covering the entire

State, or the State implementation plans

or Federal implementation plans

covering the entire group of States,

under paragraph (b) of this section

become final and federally enforceable.

(b) The Administrator may take the

actions in paragraphs (a)(1)(i) and (ii) of

this section if he or she finds that, under

the State implementation plan or

Federal implementation plan covering

the entire State or the State

implementation plans or Federal

implementation plans covering the

entire group of States:

(1) Each unit that is in the State or the

group of States and that, but for the

provisions of this section, would be

subject to emission limitations under

this part

(i) Is subject to:

(A) A cap on total annual NOX

emissions; or

(B) Two or more seasonal caps that

together limit total annual NOX

emissions;

(ii) May trade authorizations to emit

NOX within each such cap, provided

that the Administrator will consider (to

the extent demonstrated to his or her

satisfaction) 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 in lieu of emission

limitations under § 76.5, § 76.6, or § 76.7

that remain applicable under the

provisions of this section; and

(iii) Must use authorizations to emit

NOX to account for:

(A) Any NOX emissions by such unit;

and

(B) Any NOX emissions resulting from

reducing utilization of such unit below

its baseline utilization (adjusted for

changes in demand for electricity) and

shifting utilization to any other unit, or

combustion device serving a generator,

that is not subject to each such cap,

unless it is demonstrated to the

satisfaction of the Administrator that

any NOX emissions under this

paragraph (b)(1)(iii)(B) will not result in

higher total NOX emissions from sources

in the State or group of States or in other

States; and

(2)(i) Total annual NOX emissions by

all units that are in the State or the

group of States and that, but for the

provisions of this section, would be

subject to emission limitations under

this part will be equal to or lower than

total annual NOX emissions by such

units if each such unit is treated as

subject to the applicable emission

limitation in § 76.5, § 76.6, or § 76.7 that

would apply but for the provisions of

this section.

(ii) In the case of a petition under

paragraph (a) of this section, total

annual NOX emissions by the units will

be determined using the actual

utilizations of the units for the last 4

calendar quarters prior to submission of

the petition. In the case of action by the

Administrator on his or her own motion

under paragraph (a) of this section, total

annual NOX emissions by the units will

be determined using the actual

utilizations of the units for the last 4

calendar quarters prior to issuance of

the draft decision under paragraph (c) of

this section.

(c) In acting on a petition or on his or

her own motion under paragraph (a) of

this section, the Administrator will

issue, for public comment, a draft

decision on the petition or a draft

decision to act on his or her own motion

and then a final decision. The

Administrator may issue a draft

decision, but not final decision, on a

petition or on his or her own motion

before the State implementation plan or

Federal implementation plan covering

the entire State, or the State

implementation plans or Federal

implementation plans covering the

entire group of States, under paragraph

(b) of this section become final and

federally enforceable. The draft decision

will set forth procedures that will

govern issuance of the final decision

and will provide for:

(1) Service of notice of issuance of the

draft decision on.

(i) Any interested person;

(ii) The designated representative of

each source with one or more units that,

but for the provisions of this section,

would be subject to the applicable

emission limitation in § 76.6 or § 76.7;

and

(iii) The air pollution control agencies

that:

(A) Have jurisdiction over a unit

covered by the draft decision;

(B) Are in a State, or area in which

there is a federally recognized Indian

tribe, whose air quality may be affected

by the draft decision and that is

contiguous to the State, or the area in

which there is a federally recognized

Indian tribe, where a unit covered by

the draft decision is located; or

(C) Are in a State, or area in which

there is a federally recognized Indian

tribe, within 50 miles of a unit covered

by the draft decision.

(2) Publication of notice of issuance of

the draft decision in the Federal

Register and in any State publication

designed to give general public notice in

the States in which the units covered by

the draft decision are located;

(3) A public comment period of at

least 30 days and extension or

reopening of the comment period by the

Administrator for good cause;

(4) A public hearing, upon request or

on the Administrator’s own motion, to

the extent the Administrator determines

that a public hearing will contribute to

the decision-making process by

clarifying one or more significant issues

affecting the draft decision;

(5) Consideration by the

Administrator of the comments on the

draft decision received during the

public comment period or any public

hearing and written response by the

Administrator to any such relevant

comments;

(6) Notice of issuance of a final

decision using the methods set forth in

paragraphs (c)(1) and (2) of this section

for providing notice of the draft

decision; and
Federal Register / Vol. 63, No. 90 / Monday, May 11, 1998 / Proposed Rules 25975

(7) Appeals, governed by part 78 of

this chapter, of the final decision.

(d) If, after the Administrator issues a

final decision under paragraph (c) of

this section and takes the actions set

forth in paragraphs (a)(1)(i) and (ii) of

this section with regard to a State or

group of States, a State implementation

plan or Federal implementation plan

covering the entire State or entire group

of States is revised in a way that may

affect the basis for the findings on

which such decision is based, the

Administrator may, upon petition or on

his or her own motion, reconsider such

decision.

(e) For purposes of this section, the

term ‘‘State’’ shall mean one of the 48

contiguous States or the District of

Columbia.

Authority: 42 U.S.C. 7401, 7403, 7410, and

7601.

5. Part 96 is added consisting of

§§ 96.1 through 96.88 to read as follows:

PART 96—NOX BUDGET TRADING

PROGRAM

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, 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. [Reserved]

96.56 Account error.

96.57 Closing of general accounts.

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.

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.

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 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 the requirements of

this part only if such compliance is

required by a State that has jurisdiction

over the unit and that incorporates by

reference or otherwise adopts the

requirements of this part. A State that

adopts the requirements of this part

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 this part.

§ 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 Clean Air Act.

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.

Clean Air Act means the Clean Air

Act, 42 U.S.C. 7401, et seq., as amended

by Pub. L. No. 101–549 (November 15,

1990).

Combined cycle system means a

system comprised of one or more

combustion turbines, heat recovery

steam generators, and steam turbines
25976 Federal Register / Vol. 63, No. 90 / Monday, May 11, 1998 / Proposed Rules

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. For

purposes of § 96.70 and 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. For purposes of § 96.70

and 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. For purposes of

§ 96.21, § 96.42, or § 96.70 and 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. For

purposes of § 96.21, 96.42, or 96.70 and

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 the

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

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.

Compliance use date means the first

control period for which a NOX

allowance can be used for the purpose

of meeting a unit’s NOX Budget

emissions limitation.

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, a permanent record of

emissions, expressed in pounds per

million British thermal units (lb/

mmBtu) for nitrogen oxides. The

equipment also provides, for each hour,

a permanent record of emissions,

expressed in tons per hour for nitrogen

oxides. The following systems are

component parts included in a

continuous emission monitoring system:

(1) Flow monitor;

(2) Nitrogen oxides pollutant

concentration monitors;

(3) Diluent gas monitor (oxygen or

carbon dioxide);

(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.

EPA means the United States

Environmental Protection Agency.

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 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.

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
Federal Register / Vol. 63, No. 90 / Monday, May 11, 1998 / Proposed Rules 25977

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.

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

Clean Air Act and regulatory authority

under the Clean Air Act, other than title

V of the Clean Air Act 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

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 subpart

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 the tonnage equivalent of the

NOX allowances allocated to a NOX

Budget unit for use in a control period

adjusted, as of the NOX allowance

transfer deadline, by transfers to or from

the unit’s compliance account, or the

overdraft account of the source where

the unit is located, of NOX allowances

available for compliance deductions for

the unit for the control period in

accordance with § 96.54.

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 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 regional 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

being or has been submitted 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 being or has

been submitted; 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 being or

has been submitted; or
25978 Federal Register / Vol. 63, No. 90 / Monday, May 11, 1998 / Proposed Rules

(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 being or

has been submitted under a life-of-theunit, 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 being or has been submitted; 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.

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 Clean Air Act. For purposes

of section 502(c) of the Clean Air Act,

a ‘‘source,’’ including a ‘‘source’’ with

multiple units, shall be considered a

single ‘‘facility.’’

State means one of the 48 contiguous

States and the District of Columbia

specified in § 51.121(c) 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 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 Clean

Air Act and part 70 or part 71 of this

chapter.

Title V operating permit regulations

means the regulations that the

Administrator has approved as meeting

the requirements of title V of the Clean

Air Act 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 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) for use within the plant and for

sale; 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.

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.

§ 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.

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:

(a) Any unit that, any time on or after

January 1, 1995, serves a generator with

a nameplate capacity greater than 25

MWe; or

(b) Any unit that is not a unit under

paragraph (a) of this section and that,

any time on or after January 1, 1995,

does not serve a generator and has a

maximum design heat input greater than

250 mmBtu/hr.

§ 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
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B of this part) shall submit a statement

to the permitting authority otherwise

responsible for administering a 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 the

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) 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) 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 and each NOX

Budget unit at the source shall:

(i) Submit to the permitting authority

a complete NOX Budget permit

application under § 96.22 in accordance

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 and each NOX

Budget unit 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.

(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(d) 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 Clean

Air Act, 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 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
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deemed to amend automatically, and

become a part of, the NOX Budget unit’s

NOX Budget permit 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).

(2) [Reserved]

(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

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 Clean Air Act.

§ 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
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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 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

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

or notice 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.
25982 Federal Register / Vol. 63, No. 90 / Monday, May 11, 1998 / Proposed Rules

§ 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) Each NOX Budget source shall

have a federally enforceable permit,

which 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, and State and EPA

review.

(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, and

State and EPA review.

(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 with one or more NOX

Budget units 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.

(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
Federal Register / Vol. 63, No. 90 / Monday, May 11, 1998 / Proposed Rules 25983

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;

(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

allowances from or return 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.
25984 Federal Register / Vol. 63, No. 90 / Monday, May 11, 1998 / Proposed Rules

Subpart E—NOX Allowance Allocations

§ 96.40 State trading program budget.

The State trading program budget

allocated by the permitting authority

under § 96.42 will equal the total

number of tons of NOX emissions

apportioned to the NOX Budget units

under § 96.4 in the State, 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,

2005, 2006, and 2007. If the permitting

authority fails to submit to the

Administrator the NOX allowance

allocations in accordance with this

paragraph (a), the Administrator will

allocate NOX allowances for the

applicable control periods, in

accordance with § 96.42, within 60 days

of the deadline for submission by the

permitting authority.

(b) By December 31, 2002 and

December 31 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

6 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 NOX

allowances for the applicable control

period, in accordance with § 96.42,

within 60 days of the applicable

deadline for submission by the

permitting authority.

§ 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; 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

6 years before the year for which the

NOX allocation is being calculated.

(2) The unit’s total heat input for the

control periods 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 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 98

percent of the tons of NOX emissions in

the State trading program budget under

§ 96.40 in accordance with the following

procedures:

(1) The permitting authority will

allocate NOX allowances to each NOX

Budget unit in an amount equaling 0.15

lb/mmBtu multiplied by the heat input

determined under paragraph (a) of this

section.

(2) If the initial total number of NOX

allowances allocated to all NOX Budget

units in the State for a control period

under paragraph (a)(1) of this section

does not equal 98 percent of the number

of tons of NOX emissions in the State

trading program budget, the permitting

authority will adjust the total number of

NOX allowances allocated to all such

NOX Budget units for the control period

under paragraph (a)(1) of this section so

that the total number of NOX allowances

allocated equals 98 percent of the

number of tons of NOX emissions in the

State trading program budget. This

adjustment will be made by:

multiplying each unit’s allocation by the

total number of NOX allowances

allocated under paragraph (a)(1) of this

section divided by 98 percent of the

number of tons of NOX emissions in the

State trading program budget, and

rounding to the nearest whole

allowance as appropriate.

(c) 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 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 a separate allocation set-aside

for each control period. Each allocation

set-aside will be allocated NOX

allowances equal to 2 percent of the

tons of NOX emissions in the State

trading program budget under § 96.40.

(2) The NOX authorized account

representative of a NOX Budget unit

under paragraph (c) 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 is projected to commence

operation. 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 (c)(2) of this

section, the NOX authorized account

representative 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 is projected to

operate.

(4) The permitting authority will

review, and allocate NOX allowances

pursuant to, NOX allowance allocation

requests under paragraph (c)(2) of this

section in the order that the requests are

received by the permitting authority.

(i) Upon receipt of a NOX allowance

allocation request, the permitting

authority will determine whether, and

will make any necessary adjustments to

the request to ensure that, the control

period and the number of allowances

specified are consistent with the

requirements of paragraphs (c)(2) and

(3) 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 (c)(4)(i) of this section), the

permitting authority will allocate the

full, adjusted amount of the NOX

allowances requested 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 (b)(4)(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

requests under which NOX allowances
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have not already been allocated for the

control period.

(5) Within 60 days of receipt of a NOX

allowance allocation request, the

permitting authority will take

appropriate action under paragraph

(c)(4) of this section and notify the NOX

authorized account representative that

submitted the request and the

Administrator of the number of NOX

allowances (if any) allocated for the

control period to the NOX Budget unit.

(6) After September 30 of each year,

the Administrator will transfer any NOX

allowances remaining in the allocation

set-aside for the control period for the

year to the allocation set-aside for the

following control period.

(7) If additional NOX allowances are

placed in the allocation set-aside for the

control period pursuant to paragraphs

(c)(6) or (d)(2) of this section, the

permitting authority will allocate NOX

allowances, in accordance with

paragraph (c)(4) of this section, to any

NOX allowance allocation requests that

were originally denied in whole or in

part. The permitting authority will

notify the NOX authorized account

representative that submitted the

request and the Administrator of the

number of NOX allowances (if any)

allocated under this paragraph (c)(7).

(d) For a NOX Budget unit that is

allocated NOX allowances under

paragraph (c) 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.

(1) The Administrator will calculate

the number of NOX allowances to be

deducted to account for the unit’s actual

utilization using the following formula,

provided that the number of NOX

allowances to be deducted shall be zero

if the number calculated is less than

zero:

Unit’s NOX allowances deducted for

actual utilization = (Unit’s NOX

allowances allocated for control

period)—(Unit’s actual control period

utilization x 0.15 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 (c) of

this section.

‘‘Unit’s actual control period

utilization’’ is the utilization (in

mmBtu), as defined in § 96.2, of the unit

during the control period.

(2) Any NOX allowances deducted by

the Administrator in accordance with

paragraph (d) of this section will be

transferred by the Administrator to the

permitting authority’s allocation setaside for the following control period.

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 allowances

pursuant to subpart E of this part,

transfers of allowances pursuant to

subpart G of this part, and deductions

of allowances to cover NOX emissions,

account for actual utilization, or offset

excess emissions of NOX pursuant to

§ 96.54 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 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.

(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

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 the

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:

‘‘I am authorized to make this
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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 the 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 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

for a general account shall affect any

representation, action, inaction, or

submission of the 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 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, 2004, 2005,

2006, and 2007 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)

and (b) 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

NOX allowances, as allocated to the unit

under subpart E of this part or under

§ 96.88(a)(2) and (b), 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 setaside.

(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
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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) Have compliance use dates prior to

or the same as that 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(d), 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(d) 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 with a

compliance use date the same as the

year of the control period and that were

allocated to the unit under subpart E or

I of this part;

(ii) Those NOX allowances with a

compliance use date the same as the

year of the control period and that were

transferred and recorded in the account

pursuant to subpart G of this part, in

order of their date of recordation;

(iii) Those NOX allowances with an

earlier compliance use date than the

year of the control period and that were

allocated to the unit under subpart E or

I of this part; and

(iv) Those NOX allowances with an

earlier compliance use date than the

year of the control period and that were

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, with a compliance use

date the same as the year 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 their compliance use date, 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 Clean Air Act or

applicable State law. The following

guidelines will be followed in assessing

fines, penalties or other obligations:

(i) For purposes of determining the

number of days of violation, if a 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, 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.

Notwithstanding paragraph (b)(2)(i) of

this section, the Administrator will

deduct NOX allowances until the

number of NOX allowances equals the

identified percentage 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 in the year for which compliance

is being determined or, if no percentage

is identified, an equal percentage for

each such unit.

(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 [Reserved].

§ 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
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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, in

writing or in a format specified by the

Administrator, 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, in writing or in a format

specified by the Administrator,

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 Scope and 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

transferror 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 transferror 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

transferror account to the transferee

account as specified by the request,

provided that:

(1) The transfer is correctly submitted

under § 96.60;

(2) The transferror 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 with

a compliance use date that is prior to or

the same as the year of 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, in

writing or in a format to be specified by

the Administrator, 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, in writing or

in a format to be specified by the

Administrator, 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 nonrecordation.

(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) Compliance dates. (1)(i) The owner

or operator of each NOX Budget unit

under § 96.4 that commences operation

before January 1, 2000 shall ensure that

all monitoring systems required under

this subpart for monitoring NOX

emission rate and heat input are

installed, all certification tests required

under § 96.71 are successfully

completed, and all other provisions of

this subpart and part 75 of this chapter

applicable to such systems are met on

or before May 1, 2000.

(ii) The owner or operator of each

NOX Budget unit under paragraph (a)(1)

of this section that has not successfully

completed all certification tests required

under § 96.71 by May 1, 2001 shall

determine and report hourly NOX

emission rate and heat input, starting on

such date until all such certification

tests are successfully completed, using

either:

(A) The maximum potential NOX

emission rate and the maximum

potential hourly heat input of the unit;

(B) Reference methods under § 75.22

of this chapter; or

(C) Monitored data validated using

the procedures in § 75.20(b)(3) of this

chapter where the term ‘‘recertification’’

is replaced by the term ‘‘initial

certification.’’

(2)(i) The owner or operator of each

NOX Budget unit under § 96.4 that

commences operation on or after

January 1, 2000 shall ensure that all

monitoring systems required under this

subpart for monitoring NOX emission

rate and heat input are installed, all

certification tests required under § 96.71

are successfully completed, and all

other provisions of this subpart and part

75 applicable to such systems are met

on or before the later of the following

dates:

(A) May 1, 2001; or

(B) Not later than the earlier of 180

days after the date on which the unit

commences operation or, for units

under § 96.4(a), 90 days after the date on

which the unit commences commercial

operation.

(ii) The owner or operator of each

NOX Budget unit under paragraph (a)(2)

of this section that has not successfully

completed all certification tests required

under § 96.71 by the later of May 1,

2001 or the date on which the unit
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commences operation shall determine

and report hourly NOX emission rate

and heat input, starting on such date

until all such certification tests are

successfully completed, using either:

(A) The maximum potential NOX

emission rate and the maximum

potential hourly heat input of the unit;

(B) Reference methods under § 75.22

of this chapter; or

(C) Monitored data validated using

the procedures in § 75.20(b)(3) of this

chapter where the term ‘‘recertification’’

is replaced by the term ‘‘initial

certification.’’

(3)(i) The owner-operator of a NOX

Budget unit that completes construction

of a new stack or flue after the

applicable deadline in paragraph

(a)(1)(i) or (2)(i) of this section or under

subpart I of this part, shall ensure, with

regard to such new stack or flue, that all

monitoring systems required under this

subpart for monitoring NOX emission

rate and heat input are installed, all

certification tests required under § 96.71

are successfully completed, and all

other provisions of this subpart and part

75 are met not later than 90 days after

the date on which emissions first exit to

the atmosphere through such new stack

or flue.

(ii) The owner or operator of each

NOX Budget unit under paragraph

(a)(3)(i) of this section that has not

successfully completed all certification

tests required under § 96.71 by not later

than 90 days after the date on which

emissions first exit to the atmosphere

through the new stack or flue under

paragraph (a)(3)(i) of this section shall

determine and report hourly NOX

emission rate and heat input, starting on

such date until all such certification

tests are successfully completed, using

either:

(A) The maximum potential NOX

emission rate and the maximum

potential hourly heat input of the unit;

(B) Reference methods under § 75.22

of this chapter; or

(C) Monitored data validated using

the procedures in § 75.20(b)(3) of this

chapter where the term ‘‘recertification’’

is replaced by the term ‘‘initial

certification.’’

(4) The provisions of this subpart are

applicable to a unit for which an

application for a NOX Budget opt-in

permit is being or has been submitted,

as provided in subpart I of this part.

(b) Prohibitions. (1) No owner or

operator of a NOX Budget unit shall use

any alternative monitoring system,

alternative reference method, or any

other alternative for the required

continuous emission monitoring system

without having obtained prior written

approval in accordance with § 96.75.

(2) No owner or operator of a NOX

Budget unit shall operate the unit so as

to discharge, or allow to be discharged,

NOX emissions to the atmosphere

without accounting for all such

emissions in accordance with the

applicable provisions of this subpart

and part 75 of this chapter.

(3) No owner or operator of a NOX

Budget unit shall disrupt the continuous

emission monitoring system, any

portion thereof, or any other approved

emission monitoring method, and

thereby avoid monitoring and recording

NOX mass emissions discharged into the

atmosphere, except for periods of

recertification or periods when

calibration, quality assurance testing, or

maintenance is performed in accordance

with the applicable provisions of this

subpart and part 75 of this chapter.

(4) No owner or operator of a NOX

Budget unit 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)(i).

§ 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 combined 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 petition shall be resubmitted to the

Administrator under § 96.75(a) to

determine if the approval should apply

under the NOX Budget Trading Program.

(2) For any additional NOX emission

rate CEMS required under the common

stack provisions in § 75.72 of this

chapter, the owner or operator shall

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, and the

owner or operator of a NOX Budget unit

that is subject to an acid rain emissions

limitation shall meet the following

initial certification and recertification

procedures for any additional NOX

emission rate CEMS required under the

common stack provisions in § 75.72 of

this chapter.

(1) Requirements for initial

certification or recertification. (i) 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 and shall ensure that all

applicable certification tests are

successfully completed by the deadlines

specified in § 96.70(a). 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

is required.

(ii) Whenever the owner or operator

makes a replacement, modification, or

change in a certified monitoring system

that is determined by the permitting

authority or the Administrator to

significantly affect the ability of the

system to accurately measure or record

NOX emission rate 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 by

performing all of the recertification

testing required under § 75.20 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 is determined by the permitting

authority or the Administrator to

significantly change the flow or

concentration profile, the owner or

operator shall recertify the continuous

emissions monitoring system. 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. Any change to a continuous

emissions monitoring system for which
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the permitting authority or the

Administrator determines that a relative

accuracy test audit (RATA) is not

necessary, shall not require

recertification, and any other tests that

the permitting authority or the

Administrator determines to be

necessary (e.g., linearity checks,

calibration error tests, automated data

acquisition and handling system

(DAHS) verifications) shall be

performed. These other tests shall be

considered diagnostic tests rather than

recertification tests. The data validation

procedures in § 75.20(b)(3) of this

chapter shall be applied (replacing the

term ‘‘recertification’’ with the term

‘‘diagnostic’’) to linearity checks, 7-day

calibration error tests, and cycle time

tests when these are required as

diagnostic tests.

(2) Certification approval process for

initial certifications and recertification.

(i) Notification of certification. The NOX

authorized account representative shall

submit to 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

§ 75.73 of this chapter.

(iii) Upon the earlier of the successful

completion of the required certification

procedures of paragraph (b)(1) of this

section or the hour in which data that

were considered conditionally valid

according to the procedures in

§ 75.20(b)(3) of this chapter for the

monitoring system or component

thereof, the monitoring system or

component thereof shall be deemed

provisionally certified for use 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)(2)(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)(2)(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 continuous emission

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)(2)(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)(2)(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)(2)(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)(2)(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

(b)(2)(iv)(C) of this section or a notice of

disapproval of certification status under

paragraph (b)(2)(iv)(D) of this section,

then:

(A) The owner or operator shall

substitute, for each hour of unit

operation during the period of invalid

data, the maximum potential NOX

emission rate or the maximum potential

hourly heat input of the unit as

applicable, until the earlier of the time,

date, and hour (after the monitoring

system or component thereof is

adjusted, repaired, or replaced) when

certification tests are successfully

completed or the time, date, and hour

specified under the data validation

procedures under § 75.20(b)(3) 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 the procedures in

paragraphs (b)(2)(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.

§ 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 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
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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.

§ 96.74 Recordkeeping and reporting.

(a) The owner or operator of a NOX

Budget unit that is subject to an acid

rain emissions limitation shall meet

recordkeeping and reporting

requirements in subparts F and G of part

75 of this chapter and paragraph (b) of

this section, except that:

(1) For any additional NOX emission

rate CEMS required under the common

stack provisions of § 75.72 of this

chapter, the owner or operator shall

meet the requirements of paragraph

(b)(2) of this section;

(2) If the NOX authorized account

representative for the unit is not the

same person as the designated

representative for the unit under subpart

B of part 72 of this chapter, all

submissions under subpart F or G of

part 75 of this chapter must be signed

by both the NOX authorized account

representative and the designated

representative; and

(3) Each quarterly report submitted to

meet the requirements of § 75.64 of this

chapter shall also include the data and

information required in § 75.73 of this

chapter.

(b) For NOX Budget units that are not

subject to an acid rain emissions

limitation:

(1) Monitoring Plans. The owner or

operator shall comply with

requirements of § 75.62 of this chapter,

except that the monitoring plan shall

include all of the information required

by § 75.73 of this chapter.

(2) 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 including the

information required under § 75.73 of

this chapter.

(3) Quarterly reports. (i) (A) Except as

provided in paragraph (b)(3)(i)(B) of this

section, the NOX authorized account

representative shall submit

electronically a quarterly report for each

calendar quarter beginning with the

earlier of the calendar quarter that

includes the date of initial provisional

certification under § 96.71(b)(2)(iii) or

May 1, 2001. Data shall be reported from

the earlier of the date and hour

corresponding to the date and hour of

provisional certification or May 1, 2001.

(B) If the unit commences operation

after May 1, 2001, the NOX authorized

account representative shall submit

electronically a quarterly report for each

calendar quarter beginning with the

calendar quarter in which the unit

commences operation. Data shall be

reported from the date and hour

corresponding to the date that the unit

commenced operation.

(ii) Each quarterly report shall be

submitted to the Administrator within

30 days following the end of each

calendar quarter and shall include, for

each NOX Budget unit (or group of units

using a common stack), all of the data

and information required in § 75.73 of

this chapter.

(iii) 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

and fully monitored. The certification

shall state that:

(A) 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

(B) With regard to a unit with add-on

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.

(iv) The NOX authorized account

representative shall comply with all of

the quarterly reporting requirements in

§ 75.64(d), (f), and (g) of this chapter.

§ 96.75 Petitions.

(a)(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

Administrator requesting approval to

apply an alternative to any requirement

of this subpart. Application of an

alternative to any requirement of this

subpart is in accordance with this

subpart only to the extent that the

petition is approved by the

Administrator, in consultation with the

permitting authority.

(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 § 75.70 of this chapter, the

petition is governed by paragraph (b) of

this section.

(b)(1) 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. 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 § 75.50 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)(1) of this section is

approved by both the permitting

authority and the Administrator.

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, 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 that is not operating, is not eligible

to become a NOX Budget opt-in source.
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§ 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 being or

has been submitted, 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 80 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.

(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 mass

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, in writing, 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) Not withstanding 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 to be effective,

the NOX authorized account
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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 have

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 with

the same or earlier compliance use date

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.

(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 with

the same or earlier compliance use date

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 their compliance use date, 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(c) 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,
25994 Federal Register / Vol. 63, No. 90 / Monday, May 11, 1998 / Proposed Rules

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 with

the same or earlier compliance use date

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 their compliance use date, 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

(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.

[FR Doc. 98–11873 Filed 5–8–98; 8:45 am]

BILLING CODE 6560–50–P